Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION

Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Reactor Safeguards
Open Session Meeting
Docket Number:
(n/a)
Location:
Rockville, Maryland
Date:
Thursday, May 7, 2015
Work Order No.:
NRC-1552
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005
(202) 234-4433
Pages 1-83
1
1
UNITED STATES OF AMERICA
2
NUCLEAR REGULATORY COMMISSION
3
+ + + + +
4
624TH MEETING
5
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
6
(ACRS)
7
+ + + + +
8
OPEN SESSION
9
+ + + + +
10
THURSDAY
11
MAY 7, 2015
12
+ + + + +
13
ROCKVILLE, MARYLAND
14
+ + + + +
15
The Advisory Committee met at the Nuclear
16
Regulatory Commission, Two White Flint North, Room
17
T2B1, 11545 Rockville Pike, at 8:30 a.m., John W.
18
Stetkar, Chairman, presiding.
19
COMMITTEE MEMBERS:
20
JOHN W. STETKAR, Chairman
21
DENNIS C. BLEY, Vice Chairman
22
MICHAEL CORRADINI, Member-at-Large
23
RONALD G. BALLINGER, Member
24
SANJOY BANERJEE, Member
25
CHARLES H. BROWN, JR. Member
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1
DANA A. POWERS, Member
2
HAROLD B. RAY, Member
3
JOY REMPE, Member
4
PETER RICCARDELLA, Member
5
MICHAEL T. RYAN, Member
6
STEPHEN P. SCHULTZ, Member
7
GORDON R. SKILLMAN, Member *
8
9
10
DESIGNATED FEDERAL OFFICIAL:
WEIDONG WANG
ALSO PRESENT:
11
GREG BROADBENT, Entergy
12
BRYAN FORD, Entergy
13
CHRISTOPHER JACKSON, NRC
14
MEENA KHANNA, NRC
15
RICKY LIDDELL, Entergy
16
BRUCE LIN, NRC
17
JOSE MARCH-LEUBA, ORNL
18
JAMES NADEAU, Entergy
19
JERRY PURCIARELLO, NRC
20
BRIAN THOMAS, NRC
21
ALAN WANG, NRC
22
GEORGE WILSON, NRC
23
24
*Present via telephone
25
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T-A-B-L-E
O-F
C-O-N-T-E-N-T-S
OPENING REMARKS by ACRS Chairman
1.1)
Opening Statement . . . . . . . . . . . . .
4
1.2)
Items of Current Interest . . . . . . . . .
4
Grand Gulf MELLLA+ License Amendment
2.1)
Remarks by the Subcommittee Chairman
. . .
6
2.2)
Briefings by and discussions with
representatives of the Entergy and
the staff regarding the safety evaluation
associated with the Grand Gulf MELLLA+
license amendment request . . . . . . . . .
7
RG 1.27, "Ultimate Heat Sink for Nuclear
Power Plants, "Rev. 3
3.1)
Remarks by the Subcommittee Chairman
. . . 53
3.2)
Briefings by and discussions with
representatives of the staff regarding
the latest proposed revision to RG 1.27 . . 56
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1
P-R-O-C-E-E-D-I-N-G-S
2
(8:34 a.m.)
3
CHAIR STETKAR:
The meeting will now come
4
to order.
5
of the Advisory Committee on Reactor Safeguards. Here
6
at today's meeting the committee will discuss the
7
following -- Grand Gulf MELLLA+ License Amendment;
8
Regulatory Guide 1.27; Ultimate Heat Sink for Nuclear
9
Power Plants, Revision 3; and preparation of ACRS
10
This is the first day of the 624th meeting
reports.
11
This
meeting
is
being
conducted
in
12
accordance with the provisions of the Federal Advisory
13
Committee Act.
14
federal official for the initial portion of this
15
meeting.
Mr. Weidong Wang is the designated
16
We've received no written comments or
17
requests to make oral statements from members of the
18
public regarding today's sessions.
19
phone bridge line and to preclude interruption of the
20
meeting the phone will be placed in a listen-in mode
21
during the presentations and committee discussion.
There will be a
22
A transcript of portions of the meeting is
23
being kept, and it is requested that speakers use one
24
of the microphones, identify themselves and speak with
25
sufficient clarity and volume so that they can be
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1
readily heard.
2
please check and silence all of your little beepy
3
devices.
4
A
I'll remind everyone in the room to
couple
of
other
items
of
note
for
5
everyone sitting at the tables, we've made changes to
6
our microphone system here.
7
base of your little microphone there's a thing that
8
says Push.
9
on.
So if you look at the
You can now turn them off and turn them
I'd request that everybody keep your mic off
10
unless you're speaking because the rustling of the
11
papers, these mics are so sensitive that they pick up
12
and disrupt people on the bridge line that can't
13
really hear us.
14
light will come on, talk, turn it off when you're not
15
talking.
16
So just touch the Push, the little
We've got that.
Remember, Dick Skillman
17
is theoretically on a separate bridge line that should
18
be open.
19
20
Dick, are you out there?
MEMBER SKILLMAN: Good morning, John. I'm
here.
Yes, sir.
21
CHAIR STETKAR:
Excellent.
And I hope
22
you're doing well.
23
Dick was afflicted with shingles a couple of weeks ago
24
and is hopefully on the mend.
25
For those members who don't know,
You doing okay?
MEMBER SKILLMAN: I am on the mend. Thank
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1
you.
2
CHAIR STETKAR:
3
MEMBER SKILLMAN:
4
shingles shots I urge you to consider.
5
something that none of us wishes to go through.
6
as Dennis Bley wrote, the pain is really formidable.
7
So best to all.
8
Excellent.
All who haven't had
This is
And
Thank you.
CHAIR STETKAR: Glad to hear you're on the
9
mend and hope you get there.
10
MEMBER SKILLMAN:
11
CHAIR STETKAR:
Thank you, John.
With that unless any of
12
the members have anything else, the first item on the
13
agenda is the Grand Gulf MELLLA+, and Dr. Joy Rempe
14
will lead us through that session.
15
MEMBER REMPE:
Joy?
Thank you, Mr. Chairman.
16
On March 17th, our Power Uprates Subcommittee reviewed
17
the
18
license amendment request to allow operation in the
19
expanded Maximum Extended Load Line Limit Analysis
20
Plus, or MELLLA+ domain.
Grand
21
Gulf
At
Nuclear
the
end
Station
of
Unit
our
1
operating
meeting,
our
22
subcommittee recommended that this LAR be presented to
23
the full committee.
24
MELLLA+ domain is the second to be reviewed by us.
25
The first was the Monticello Nuclear Generating Plant.
This LAR for operation in the
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1
And you shall hear today, several features
2
of Grand Gulf which differ from Monticello are of
3
particular
importance
4
operation.
Today we're going to hear presentations
5
from
6
licensee, Entergy Operations Incorporated, and part of
7
the presentations will be closed in order to discuss
8
information that's proprietary to the licensee and its
9
contractors.
the
NRC
staff
with
and
respect
to
representatives
MELLLA+
from
the
10
And I believe we're going to start today
11
by hearing is it from George, or -- okay, yes, Wilson
12
from the staff.
13
MR. WILSON:
Good morning.
I'm George
14
Wilson, deputy director of the Division of Operating
15
Reactor Licensing.
16
opportunity to brief the committee on the MELLLA+
17
amendment for Grand Gulf.
I want to thank you for this
18
The staff and the licensee last met with
19
the ACRS subcommittee on this review on March 17th.
20
The NRCS staff has determined that the operation in
21
the MELLLA+ domain at the Grand Gulf Nuclear Station
22
provides additional operational flexibility while not
23
compromising the safety of the plant.
24
At this point I'd like to turn the meeting
25
over to Meena Khanna, the branch chief for Plant
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1
Licensing 4-2 which includes Grand Gulf.
2
MS. KHANNA:
Meena?
Thank you, George.
Good
3
morning.
As George indicated, my name is Meena
4
Khanna.
5
Operating Reactor Licensing. Today we will be talking
6
to you about the review of the Grand Gulf MELLLA+.
I am a branch chief in the Division of
7
The
Entergy
license
amendment
request
8
dated September 25th, 2013 proposes a revision to the
9
Grand Gulf Nuclear Station technical specifications to
10
allow plant operation from the currently licensed
11
maximum extended load line limit analysis, MELLLA,
12
domain to plant operation in the expanded MELLLA+
13
domain under the previously approved extended power
14
uprate conditions of 4408 megawatts-rated core thermal
15
power.
16
An EPU was approved by license amendment
17
number 191 dated July 8, 2012 for Grand Gulf that
18
increased the power level from 3898 megawatts-thermal
19
to 4408 megawatts-thermal.
20
MELLLA+ domain, the operating power is maintained
21
constant but the recirculation core flow is allowed to
22
operate under a wider window than under the MELLLA
23
conditions.
24
25
When operating in the
For Grand Gulf, the MELLLA+ flow window is
between
80
percent
and
105
percent
flow.
This
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1
operating flexibility reduces the need for frequent
2
control rod motion. I'd like to note that this is the
3
NRC
4
implementation of the MELLLA+ domain, Monticello being
5
the first.
6
approved MELLLA+ licensing topical report NEDC-33006,
7
Revision 3, which is General Electric Boiling Water
8
Reactor Maximum Extended Load Line Limit Analysis Plus
9
for its submittal.
staff's
second
review
of
the
request
for
In both cases the licensees used the GEH
10
A portion of the NRC staff's presentation
11
today will include a comparison of the significant
12
differences between the Monticello and Grand Gulf
13
MELLLA+ license amendment reviews. As first indicated
14
previously, we did have an NRC subcommittee review
15
meeting in March, and through that meeting there were
16
several
17
subcommittee.
18
questions.
questions
that
were
raised
by
the
We have responded to all of these
19
Again I will reiterate that the staff has
20
determined the operation in the MELLLA+ domain at the
21
Grand Gulf Nuclear Station does provide additional
22
operational flexibility while not compromising plant
23
safety.
24
currently have two additional MELLLA+ applications in-
25
house for Nine Mile Point and Peachbottom.
In addition, I would like to note that we
Both of
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1
these applications are currently under staff review,
2
and
3
committee, will be scheduled in the near term.
4
thank you for your time.
the
ACRS
meetings,
subcommittee
and
full
We
5
At this point I would like to turn the
6
meeting over to Bryan Ford of Entergy for their
7
presentation
8
application for Grand Gulf.
9
of
MEMBER
the
MELLLA+
REMPE:
license
amendment
Thank you.
While
we're
switching
10
speakers, Dick, is there a way to turn your phone on
11
mute?
12
noise, I think, from your phone.
13
14
MEMBER SKILLMAN:
I will go ahead and do
it right now.
15
16
Because we're getting a lot of background
MEMBER
REMPE:
Thank
you.
Sorry
to
request it, but it'll help.
17
MR. FORD:
Well, good morning everybody.
18
My name is Bryan Ford.
I'm the senior manager of
19
Regulatory Assurance for Entergy. Thank you very much
20
for taking the time to look at our MELLLA+ submittal
21
today.
22
for the plant going forward.
It's going to provide some good flexibility
23
So today with me I have Greg Broadbent,
24
the supervisor of Fleet Nuclear Safety Analysis; Jim
25
Nadeau, the Grand Gulf Regulatory Assurance manager;
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and
Ricky
Liddell,
the
supervisor
2
Operations Training for Entergy.
at
Grand
Gulf
3
Today what we're going to discuss is a
4
brief overview of the plant and the benefits that
5
we're getting out of the MELLLA+ analysis.
6
going to talk a little bit about the safety analysis
7
methods.
8
9
We're
We're going to show a short video on the
prime
area
operator
action
associated
with
the
10
analysis.
We're also going to discuss the ATWS-I
11
analysis that was performed to support the amendment,
12
and we're going to talk about the license condition
13
associated with it.
14
to Jim Nadeau.
With that I want to turn it over
15
MR. NADEAU:
Thanks, Bryan, and thank you
16
to the committee for hearing us.
17
Nadeau. I'm the Regulatory Assurance manager at Grand
18
Gulf and I'm going to give a brief overview of Grand
19
Gulf and MELLLA, why we want it.
Again I'm Jim
20
Grand Gulf was initially licensed in 1984,
21
became commercially operational in July 1st, 1985. We
22
are a GE BWR 6 with a Mark III containment.
23
originally licensed in 1984 to 3833 megawatts-thermal,
24
and we're currently operating license limited at 4408
25
megawatts-thermal.
We were
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1
The MELLLA+ offers us improved operational
2
flexibility in this extended region of 4408 megawatts-
3
thermal.
4
manipulations, reduced operator challenges and reduced
5
enrichments.
It
6
gives
us
reduced
reactivity
Next slide.
The
graph
in
front
of
you
shows
the
7
current power-flow map.
8
the black line. The MELLLA+ region is the blue region
9
that we're requesting and this gives us additional
10
flexibility to operate reactor flows to change reactor
11
reactivity.
12
That's the white area inside
As Meena was talking earlier, we've gone
13
through the licensing.
14
conditions
15
We've met all 80.
16
staff.
17
at the Grand Gulf facility in the simulator to show
18
that we could meet our operate time-critical operator
19
actions.
20
21
that
were
We've had 80 limitations and
in
the
licensing
documents.
And we've had two audits by the NRC
One at GE Hitachi in April 2014, and also one
In both cases the audits were successful.
MEMBER BANERJEE:
Ask you a question.
I
missed this in the subcommittee meeting, but --
22
CHAIR STETKAR:
Sanjoy, it's one thing to
23
turn the mic on, another thing to be sort of close to
24
it.
25
MEMBER BANERJEE:
All these things that I
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1
have to learn towards the end of my career.
But
2
whatever.
3
I remember, was the turbine trip, right, without
4
bypass?
Your limiting transient for your ATWS, if
5
MR. NADEAU:
6
MEMBER BANERJEE: Now if I should ask this
7
in the closed session just say so, but that's fine.
8
Whereas, the things that challenge the DSSCD mostly
9
are the two RPT trip in terms of stability, and if I
10
remember with Monticello that was the same thing. Why
11
is that the case?
12
13
MR.
Without bypass.
NADEAU:
Greg,
is
this
a
closed
session?
14
MR. BROADBENT:
Yes, that's something we
15
can discuss in the closed session. We'll have a GE up
16
here and we can talk the details.
17
MEMBER BANERJEE:
Yes, I sort of missed
18
that until I started to look at your things in more
19
detail.
20
MR. BROADBENT:
Yes, I'm not sure if we
21
went into a whole lot of detail on that particular
22
subject area, but --
23
MEMBER BANERJEE:
24
MR. NADEAU: Okay, now I'd like to turn it
25
Yes.
Okay.
over to Greg Broadbent.
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1
MEMBER
SCHULTZ:
One
question.
You
2
mentioned you have 80 limitations.
3
were also conditions associated with the application
4
of MELLLA+. Are there no longer conditions associated
5
with the application?
6
MR. NADEAU:
the
There are license conditions
7
associated
8
incorporating through our license.
9
about that later in the presentation --
10
MEMBER SCHULTZ:
11
MR. NADEAU:
12
with
I thought there
application
which
we're
We'll be talking
That's fine.
Thank you.
-- directly related to time-
critical actions.
13
MEMBER SCHULTZ:
14
MR. BROADBENT:
Understood.
Thank you.
And I'm Greg Broadbent,
15
the Entergy Nuclear Analysis supervisor in corporate.
16
With regard to the MELLLA+ analysis, we followed the
17
guidelines and the standard GE MELLLA+ topical report,
18
33006.
19
The most challenging, the most different
20
analysis associated with MELLLA+ is the ATWS analysis,
21
and that's because in MELLLA+ you're operating a
22
higher rod line.
23
detail for the subcommittee.
24
pumps trip you end up at a higher ATWS post-trip power
25
level and that causes things to happen faster.
We presented this in some more
But when the recirc
PCT
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1
increases faster.
The pool heats up faster and
2
necessitates the need for quicker operator actions.
3
And we have a 90-second operator action time to reduce
4
reactor water level.
5
SLC is assumed in the analysis to happen
6
at 300 seconds, and then to cool the suppression pool
7
we put RHR and suppression pool cooling in 11 minutes.
8
Now we recognize that the 90 seconds is a relatively
9
fast operator action time, and I think we've got a
10
video that Ricky will present that will go in a little
11
bit more detail.
12
MR. LIDDELL:
Good morning.
I'm Ricky
13
Liddell.
14
morning, showing that we do in fact meet the 90-second
15
time-critical action for determining feed flow to the
16
vessel to reduce level.
17
Monticello plant, and basically our operator response
18
is similar to theirs.
19
second time-critical action as were we.
20
cue up the video now.
21
22
I will be walking us through the video this
We did do a benchmark at the
They were able to meet the 90-
MEMBER REMPE:
And so I'll
Before you do that I have
a question about the last bullet.
23
MR. LIDDELL:
Sure.
24
MEMBER REMPE: The video, my understanding
25
was the operators were given some training and they
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1
knew that that transient was going to occur.
2
MR. LIDDELL:
That's correct.
3
MEMBER REMPE:
And will the training be
4
the same way or are you going -- there's one thing to
5
be told to do something and then you execute that
6
action, and then there's another thing to be sitting
7
in
8
transient to occur.
9
in certain --
the
control
10
room
and
have
an
accident
or
a
And how do you account for that
MR. LIDDELL:
Our training in the staff,
11
me and two of my instructors put that video together
12
in a couple of hours.
13
would need to implement the actions to meet the 90
14
seconds.
15
doing the same actions that we already do for an ATWS
16
response.
17
communication between the CRS and the operators.
18
We looked at our EPs and how we
And essentially what we're doing is we're
We're
just
eliminating
the
three-part
Now we were able to put that together
19
pretty quickly with a minimum of training.
20
going to give a minimum of two cycles of training to
21
our operators, so they're going to have to cue off of
22
an update from the at-the-controls operator that we're
23
in a high power ATWS and they will know what actions
24
to take based on that.
25
VICE CHAIR BLEY:
We're
Ricky, I don't remember
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1
from the subcommittee meeting, I don't recall anyone
2
talk about that for this activity you suspended the
3
three-way communication that you just said.
4
MR. LIDDELL:
5
VICE CHAIR BLEY:
6
What we're doing is -I mean that gets you
done faster but it might get something else done.
7
MR.
LIDDELL:
Yes,
we
have
several
8
actions, time-critical actions that we do already in
9
response to a reactor scram or a turbine trip.
So
10
immediate operator actions have to be performed by
11
memory.
12
direct and the operator is expected to recognize the
13
three conditions for those --
14
VICE CHAIR BLEY:
15
They're not required to have a supervisor
Do they have a post-
activity communication requirement?
16
MR. LIDDELL:
Yes.
Since the standard
17
heat reports that I did immediate actions one, two and
18
three, that's correct.
19
20
MEMBER
BROWN:
Does
(Simultaneous speaking.)
22
MR. LIDDELL:
And I'll explain what the
cues are.
24
25
simulation
actually show the trigger or what alerts the operator?
21
23
the
MEMBER SKILLMAN:
Skillman.
Ricky, this is Dick
Can you hear me, please?
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1
MR. LIDDELL:
Yes.
2
MEMBER SKILLMAN:
Sir, what I want to ask
3
you is a reinforcement of Dr. Rempe's question.
4
I heard you just say is that there are other events
5
for which you have immediate operator actions, your
6
TCOAs, time-critical operator actions, and that your
7
operator's performance for those events coupled with
8
what you witnessed in the ATWS give you confidence
9
that the TCOAs will be accomplished in the required
10
time period. In other words, you're building not only
11
on the ATWS event but on other similar events that
12
cause the operators to take immediate manual actions.
13
Is that what you intend to communicate?
14
MR. LIDDELL:
Yes, sir.
What
If we're in an
15
ATWS and let's say we had other off-normal events that
16
had immediate actions, the ATWS and entry into our
17
EP2A would be the overriding priority, and it already
18
is.
19
secondary to our ATWS EP directions.
We respond to other immediate actions already as
20
MR. FORD:
And this is Bryan Ford.
A
21
little bit more clarification.
During our training,
22
one of our license conditions is to document the
23
amount of time it takes for our different shifts to
24
perform this action and to provide a report to the
25
staff that shows that we were able to meet it for the
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1
applicable shifts.
2
MEMBER SKILLMAN:
3
other
immediate
4
transients
5
required compliance as ATWS?
6
or
Thank you.
time-critical
events
that
MR. LIDDELL:
actions
are
No.
Are there
just
for
as
other
stringent
But we do have other
7
immediate actions that we take for such as a jerking
8
control rod, the operator's supposed to immediately
9
drive that control rod fully in.
rod
drive
pump,
the
So the trip of a
10
control
operator
immediately
11
recognizes that and starts the second, the standby
12
pump.
13
So those are the kind of critical, not
14
time-critical but I would say time-sensitive actions
15
that we do have in place.
16
MEMBER SKILLMAN:
And what is the track
17
record for operator response?
18
response not rehearsed to those types of events?
19
MR. LIDDELL:
Spontaneous operator
I can give you an example.
20
Recognition of THI, thermal hydraulic instability, we
21
have some scenarios last cycle with that. And I think
22
the longest for an operator to recognize that and take
23
an
24
availability of the indications. So for the ones that
25
we train on as immediate operator actions we have not
action
was
about
ten
seconds
based
on
the
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1
seen any specific weaknesses in the operator response.
2
3
VICE CHAIR BLEY:
isolated event, right, or was it a simulator?
4
5
Ricky, that was a real
MR.
simulator.
LIDDELL:
No,
ours
was
in
There was --
6
(Simultaneous speaking.)
7
MR. LIDDELL:
8
VICE CHAIR BLEY:
Okay.
9
MEMBER SKILLMAN:
Ricky, thank you.
10
the
But it was not ours.
MR. LIDDELL: Sure. I'm going to go ahead
11
and expand this.
12
the locations on the panels where there will be
13
actions that'll be taken initially.
14
and I apologize for the ones that are on conference
15
call, but I'm looking at the full core display.
16
We
What I'll do first is just discuss
have
our
This is the --
at-the-controls
operator
17
seated in the controls area, and he will receive a
18
couple of alarms indicating a scram and we'll respond
19
to those with the immediate operator actions for a
20
scram.
21
condition then he will provide an additional update
22
for that which will be the cue for he and the second
23
operator and also the CRS to enter the EP2A which is
24
our ATWS emergency procedure.
25
Once
he
recognizes
that
we
have
a
ATWS
So we have --
VICE CHAIR BLEY: Just for everybody here,
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1
for you guys, the CRS is the SRO.
2
MR. LIDDELL:
That is correct.
Control
3
room supervisor. And what, his desk is off-camera but
4
for EPs and off-normal events he would move down to
5
the control room operator's desk and so he'll come
6
into view which will be me.
All right.
7
MEMBER BROWN: Before you -- where are the
8
alarms indicated where this operator is going to
9
respond to?
10
MR. LIDDELL:
Okay.
What we're going to
11
get is I've got to get reactor scram alarms right here
12
on the indicators next to the full core display.
13
what he has to do is to test, verify that all rods are
14
in.
15
result of the scram signal.
16
So
And
In this case there will be no rods inserted as a
we'll
remain
in
100
percent
ATWS
17
condition until we will get a recirc pump trip that
18
will occur on pressure because of the turbine trip.
19
Even though we have bypass we'll still have high
20
reactor pressure, enough that we will get an automatic
21
actuation of the recirc pump trip and alternate rod
22
insertion.
23
Now there will be some additional alarms
24
that you can see over here on this left side of the
25
680 panel.
So those will be an indication that ARINEAL R. GROSS
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1
RPT, alternate rod insertion-recirc pump trip has
2
actuated.
3
action to downshift the recirc pumps and to initiate
4
ARI-RPT will not be required.
5
operator to go ahead and go through those just to
6
verify that all those signals are received.
7
will see him initiate those actions, but we can tell
8
by the alarms that they've actually already occurred.
Now what that means for us is the operator
9
10
MEMBER BROWN:
We do expect the
So it's the absence of the
rods, you've got a scram but no rods go to the bottom.
11
MR. LIDDELL:
12
(Simultaneous speaking.)
13
MEMBER BROWN:
14
That's right.
There's some other, it's
the turbine trip that comes along with it?
15
16
MR. LIDDELL:
If I get indications of a
turbine trip, you know, have indications of a scram --
17
MEMBER BROWN:
18
(Simultaneous speaking.)
19
MEMBER BROWN:
20
So you
I'm just trying to --
-- the two or three things
he's going to cue on that he has to see to say okay.
21
MR. LIDDELL:
The APRM that you've got
22
four channels of average power range monitors on that
23
section of the panel and they will, even after the
24
recirc pump trip they will still be indicating about
25
40 percent.
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1
MEMBER BROWN:
2
MR. LIDDELL:
So you'll hear him give an
3
update, 40 percent ATWS.
That 40 percent is the 40
4
percent for thermal power that we still have after the
5
recirc pump trips.
6
response that's going to drive power down otherwise we
7
would still have 100 percent. But that pressure spike
8
is going to initiate automatic response.
9
Because that's the initial plant
MEMBER BROWN:
10
Okay.
MR. LIDDELL:
Okay, thank you.
Now also on this section of
11
the panel to the left of the at-the-controls operator
12
are
13
operator will actually respond to control feedwater.
14
The at-the-controls operator after verifying that we
15
are in an ATWS and taking initial actions to verify
16
that the recirc pumps are downshifted and tripping one
17
feed pump, now we trip one feed pump because the
18
feedwater control system is going to ramp injection
19
back as far as it can.
the
feedwater
controls.
This
control
room
20
But the feed pump speed with both feed
21
pumps still in service are really going to feed more
22
than we need in this situation, so tripping one
23
feedwater pump will reduce feedwater injection and
24
allow us to maintain the level.
25
Now our initial actions are really just to
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1
stabilize level. I will give, or the CRS will give an
2
order to terminate and prevent feedwater injection,
3
and that includes not only just reducing the injection
4
to zero but isolating the flow paths so that if
5
reactor pressure were to drop we wouldn't get an
6
inadvertent feedwater injection.
7
terminate
8
terminate feed flow and also isolate the flow paths to
9
prevent the injection.
and
10
prevent
encompasses
CHAIR STETKAR:
So that order of
all
actions
to
Ricky, just education
11
because I come out of the PWR world and I sort of know
12
how boilers work, but as you get out of the initial
13
transient how are they instructed to control level
14
after that?
15
What do they do?
MR. LIDDELL:
The EPs, EP2A will drive
16
that.
What they'll do is CRS will give out a lowered
17
level band.
18
going to be minus 70 inches wide range to minus 130
19
inches wide range.
20
we'll call a start-up lineup.
21
22
In this case the initial level band is
We'll line up the feedwater in a,
CHAIR STETKAR:
Okay, but they do restore
feedwater flow?
23
MR. LIDDELL:
Correct.
24
CHAIR STETKAR:
25
MR. LIDDELL:
Okay.
And you'll see that action.
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1
That'll be one of the first things that he does is to
2
terminate feedwater and then line up in the start-up
3
level lineup.
4
A few other actions that are going to
5
occur, if you look over to the right side this is our
6
601 panel which has our SRVs, standby liquid control.
7
The
8
inadvertently initiate on a low level.
SRVs,
we
want
to
make
sure
that
they
don't
9
So one of the first actions in our ATWS
10
response is to inhibit ADS, so you'll hear that order
11
given.
12
And
13
switches, so that's one of the first actions that'll
14
be taken.
Inhibit alternate depressurization system.
that's
done
with
just
two
switches,
keylock
15
Also high pressure core spray, since it
16
will initiate on a level 2 which we will receive a
17
level 2 when we start lowering, we want to override
18
high pressure core spray before we start lowering
19
level to the point of initiating high pressure core
20
spray.
21
So the initial actions that you'll see
22
will be the at-the-controls operator will respond to
23
the scram, take the mode switch to shutdown, recognize
24
that the rods are still out and we're at approximately
25
40 percent based on APRM indications.
He'll give an
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1
update and then once he gets the update the other
2
operator then knows that he needs to go inhibit ADS
3
and override high pressure core spray.
4
The at-the-controls operator will also
5
trip a feed pump, and at that point the control room
6
operator will come back over and take over feedwater
7
and then he will maintain feedwater through the rest
8
of the event.
9
10
MEMBER SCHULTZ:
Inhibiting the ADS is
time-critical?
11
MR. LIDDELL: It is not. It's not a time-
12
critical action specifically, but it's one that we do
13
in parallel with the others.
14
are ordered such that before you terminate and prevent
15
feedwater injection you take those other actions, so
16
they'll be doing those first.
Our EP initial actions
17
And those are some of the actions that if
18
we don't get those done immediately we can't get to
19
the step to terminate and prevent feedwater. So it is
20
important that they do those as immediate actions
21
without having to wait for the CRS to give that
22
command.
23
MEMBER SCHULTZ:
24
MR. LIDDELL:
25
start the video.
Thank you.
All right, so I'm going to
And I'm not getting, I don't see a
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1
timeline.
2
3
MR. FORD: You'll have to make it a little
smaller.
4
MR. LIDDELL:
All right, yes, this will
5
work.
So what I'm going to do is I'm going to go
6
ahead and run the video one time through and it'll
7
take just a couple of minutes.
8
and I'll freeze it at certain points, anybody wants me
9
to stop at a certain point.
And then I'll go back
But I think it would be
10
good to run through it one time without stopping just
11
to give you an idea of the actions and the time frame
12
that they tell you.
13
(Video played.)
14
MR. LIDDELL:
(Narrating)
The reactor
15
scram alarms are coming in, and also -- now the at-
16
the-controls operator, he's verifying that the recirc
17
pumps have tripped. The other operator has overridden
18
high pressure core spray and inhibited ADS.
19
coming around to take over feedwater now.
He's
20
He's now reducing injection. That's where
21
we'd get our high pressure core spray initiation if it
22
hadn't already been overridden.
23
there.
24
(Video stopped.)
25
VICE CHAIR BLEY:
Okay, I'll stop it
When you run it again
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1
would you stop at the point they do the things they
2
need to do in 90 seconds?
3
MR. LIDDELL:
Absolutely.
4
VICE CHAIR BLEY:
5
MR. LIDDELL: So on our timeline right now
6
we're two minutes and 55 seconds from the start of the
7
video.
8
we're about two minutes and 45 seconds in.
9
standby
Yes, thanks.
The scram came in at about ten seconds, so
liquid
control
which
that's
10
activity so that has been completed.
11
second for the terminate and prevent.
12
will freeze it.
13
(Video played)
14
MR. LIDDELL:
(Narrating)
a
Our
300-second
And the 90-
So this time I
Now he just
15
tripped a feed pump which is going to help with our
16
level.
17
18
MR. MARCH-LEUBA: Can you freeze it there?
Can you freeze it?
19
(Video stopped.)
20
MR. LIDDELL:
21
MR. MARCH-LEUBA: Yes, this is Jose March-
Sure.
22
Leuba.
23
they identify the scram happen?
24
25
Can you point out the line, the alarms where
MR. LIDDELL: Yes. All right, let me back
up.
Okay, so at this point we've got a couple of red
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1
alarms here.
There's also going to be one that comes
2
in here.
3
multiple scram signals. We're going to get, initially
4
you just get the reactor scram and based on that alone
5
his immediate action is to verify that the rods are
6
inserted, which they're not, take the mode switch to
7
shutdown which actually gives two additional signals
8
for shutdown and they don't cause the rods to insert
9
either.
What's happening is we're going to get some
10
So at that point the recirc pumps have
11
tripped on high pressure and he's going to look and
12
recognize that we're at a 40 percent power.
13
MR. MARCH-LEUBA:
So this is Jose again.
14
Before operator got off the chair he already knew the
15
scram was supposed to happen because he saw those red
16
lights, correct?
17
MR. LIDDELL:
That's correct.
18
MR. MARCH-LEUBA:
And now he's looking
19
probably at the APRM display to see where the power
20
is?
21
MR. LIDDELL:
22
MR. MARCH-LEUBA:
23
Can you point where the
control rod insertion will show up?
24
25
That's correct.
MR. LIDDELL:
Yes.
This section here is
just a graphical display of the core.
All this red
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1
should
2
indication green lights on all of these rods. So just
3
based on a glance, you know, we all can see that this
4
is red and not green.
5
6
be
all
green.
You
should
have
full-in
So that's your first.
MR. MARCH-LEUBA: What initiated the scram
in this case?
7
MR. LIDDELL:
The turbine trip initiated
8
the scram on high pressure.
That's going to be the
9
first one you're going to get.
You're also going to
10
get an APRM flux scram, then he's going to get, due to
11
the level at, pretty soon you'll get a level scram
12
signal.
13
So there's multiple scram signals that are
14
coming in, but initially the pressure because you've
15
basically got 100 percent power you've only got 30
16
percent capacity on your bypass valves, so you're
17
going to be lifting SRVs over here but that happens
18
after your scram signal.
19
20
CHAIR STETKAR:
with bypass as opposed --
21
MR. LIDDELL:
22
MR. LIDDELL:
23
Turbine trip with bypass.
We ran them both.
The
response of the crews is the same but --
24
25
This is the turbine trip
CHAIR STETKAR:
The timing, you know, the
level response will be a little different.
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1
2
MEMBER BANERJEE:
This is 100 percent
power, is it?
3
MR.
LIDDELL:
Initially
we're
at
100
4
percent power. With the scram signal until the recirc
5
pumps
6
percent.
7
you're going to have boiling in the core and --
trip
10
MEMBER
pressure
we're
still
at
100
BANERJEE:
Does
it
make
any
difference if you're at 80 percent flow or something
or what's the flow again?
11
12
high
But as soon as the recirc pumps trip then
8
9
on
MR. LIDDELL:
Full flow, full power.
I think that this one
over --
13
MR. BROADBENT:
Yes, this was from the
14
MELLLA+ region so this is the highest rod line that we
15
can get to.
16
MR. MARCH-LEUBA: This is Jose again. You
17
guys
know
18
complicated.
19
factor point of view, which is the one we're really
20
more concerned about, before operator got off the
21
chair he'd already seen that the scram signal had
22
happened and the rods had not gone in. So even before
23
he got off the chair, two or three seconds, he knew
24
that he was in an ATWS.
25
too
much
and
are
making
it
a
little
Ultimately the point from the human
MEMBER BANERJEE:
Yes.
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1
2
MR. MARCH-LEUBA: It was going through his
mind what do I have to do next.
3
4
MEMBER BANERJEE:
Yes, I'm just trying to
establish the initiating conditions.
5
MR. MARCH-LEUBA:
Yes, that's important.
6
But from the human factor point of view it's not that
7
complicated.
8
(Simultaneous speaking.)
9
MEMBER BANERJEE:
Eighty percent flow?
10
MR. BROADBENT:
11
MEMBER BANERJEE:
12
Eighty percent.
Eighty percent flow,
that's been established and it's a turbine trip.
13
VICE CHAIR BLEY:
I'm sorry.
Jose, from
14
a thermal hydraulics point of view you're right.
15
guy in the control room, the complication is what
16
makes his job.
17
18
MR.
MARCH-LEUBA:
Correct.
He's
The
to
oversee --
19
VICE CHAIR BLEY:
This all matters.
20
MR. MARCH-LEUBA:
He needs to go through
21
everything.
22
VICE CHAIR BLEY:
I have just a quick
23
question, Ricky, on what you guys do.
I noticed this
24
and I noticed nobody looking at it, or maybe you were
25
looking at it.
The guy said, I'm going to do an
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1
update, and the other two guys hold their hands up.
2
So at the CRS if he didn't see the other hand go up
3
would say, wait a minute.
4
5
MR. LIDDELL:
VICE CHAIR BLEY:
up.
MR. LIDDELL:
Okay.
No, the hands going
up is something that we've adopted just to make sure
10
that
11
everybody's listening.
whoever's
12
13
I saw two hands going
I was, oh that's weird.
8
9
You're fixing to get
some information -- that's right.
6
7
Yes.
giving
the
VICE CHAIR BLEY:
But go ahead.
update
knows
that
But his back's turned.
Every time.
14
(Video played.)
15
MR. LIDDELL:
(Narrating)
All right, so
16
just a couple of seconds.
The mode switch is in
17
shutdown.
18
scram signal but it's not going to make a difference.
We're just going to give you a redundant
19
(Video stopped.)
20
MEMBER BANERJEE:
Okay, so at this point,
21
31 seconds, we've taken the two actions to inhibit
22
ADS, override high pressure core spray.
23
through the actions to ensure that ARI-RPT has been
24
initiated.
25
alarm and tripped one feed pump.
He has gone
It did auto-initiate based on this red
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1
2
MEMBER BALLINGER:
The board is still red
though, right?
3
MR. LIDDELL:
That's correct.
4
(Video played.)
5
(Video stopped.)
6
MR. LIDDELL:
Now what this operator's
7
doing right now, he hasn't been given an order to
8
terminate and prevent feedwater, so but what he is
9
doing is lining up the feedwater system so that he can
10
maintain in a band.
And what he's going to have to do
11
is he's going to reduce the pump speed so that he
12
stops injection and he's going to isolate that flow
13
path.
14
And he's going to have to walk around to
15
this other panel and line up the start-up level
16
control flow path, so you'll see at one point he's
17
walking away from the panel.
18
action that he has to do to complete the terminate and
19
prevent process.
20
going to where he needs to be to complete that action.
21
But the key point here is once he has
That's part of his
So don't think -- you know, he's
22
terminated injection that action is complete.
To be
23
able to prevent a subsequent injection he has some
24
other actions, but as far as the initial action to
25
terminate feed flow that will be complete, and I'll
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1
show you when that happens.
2
VICE
CHAIR
3
around?
4
actions or something?
BLEY:
he
carrying
Is that a little check sheet for immediate
5
MR. LIDDELL:
6
MR. FORD:
7
action, is the 90-second action.
That's correct.
So he's just about to take the
8
MR. LIDDELL:
9
(Video played.)
10
(Video stopped.)
11
MR. LIDDELL:
12
What's
That's correct.
Okay, now he was already
reducing feed flow, and I'll show at what point.
13
(Video played.)
14
MR. LIDDELL:
15
he's reducing injection right there.
(Narrating)
16
(Video stopped.)
17
MR. LIDDELL:
All right, so
He's done at that point,
18
okay.
He initiated the action.
19
know, five or so seconds.
20
had seven seconds, so nine and three, you know, we're
21
at about 85 seconds for him to complete the action,
22
but he had already reduced the injection flow several
23
seconds before that.
24
25
It took about, you
So right now we're at, we
VICE CHAIR BLEY: And that's the 90-second
action.
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1
2
MR. NADEAU:
The 90-second action is to
initiate.
3
MR. LIDDELL:
That's right.
4
MALE PARTICIPANT:
5
CHAIR STETKAR:
Initiate what?
Initiate, well, I mean,
6
you know, you can call initiate tripping the first
7
feed pump.
But is it --
8
9
MR. LIDDELL:
That's true, but there's
several things that are happening to reduce injection
10
rate.
But
11
terminated, which he has right here, it's about 85
12
seconds.
13
when
he
finally
CHAIR STETKAR:
has
all
injection
So is the time window to
14
get injection flow to, I'll use the term "zero," or is
15
it the time to get injection flow less than normal
16
injection, to start getting injection flow less than
17
normal?
18
MR. LIDDELL:
19
CHAIR
It is to reduce, we're --
STETKAR:
What
I'm
trying
to
20
understand is he very quickly trips the first feed
21
pump.
That drops it probably to 70 percent, roughly.
22
23
VICE CHAIR BLEY:
And is that the 90-
second time window or is it to get it to zero?
24
MR. LIDDELL:
25
CHAIR STETKAR:
No.
Or actually to get level
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1
down to --
2
MR. NADEAU:
Is not to get it zero.
Very
3
quickly at about 20 seconds when he trips the first
4
feed
5
initiation of reducing flow.
pump
that
is
not,
we
have
6
(Simultaneous speaking.)
7
MR. NADEAU:
8
MEMBER REMPE:
9
report to the NRC for your condition.
not
completed
About 60 seconds.
So this is the time you
10
(Video played.)
11
(Video stopped.)
12
MR. LIDDELL:
So he is reducing feed flow
13
at this point and this is, you know, 78 seconds.
14
approximately at 71 seconds he's taken the action
15
that --
16
17
VICE CHAIR BLEY: So that's the 90 seconds
then is when you actually start running it back.
18
MR. NADEAU:
19
VICE CHAIR BLEY:
20
didn't quite understand.
21
seconds.
That's right.
Okay.
That's what we
And for this case that's 70
22
(Video played.)
23
VICE CHAIR BLEY:
24
So
This case is pretty
clean.
25
(Video stopped.)
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1
2
MR. NADEAU:
on the video?
3
4
Are there any more questions
CHAIR STETKAR: Charlie. Push the button,
Charlie, when you're going to talk.
5
MEMBER BROWN: Oh that's right. Can I ask
6
the question again since he didn't hear me?
7
think I needed that but --
8
CHAIR STETKAR:
9
I don't
Well, it's the recorder
because the mics only go to the recorder.
10
MR. LIDDELL:
So to answer your question,
11
one of the things that we do early on is we'll call
12
for three attachments to be installed which will
13
bypass the interlocks that prevent us from inserting
14
control rods.
15
us from resetting the scram and allow us to take
16
actions to start inserting rods.
They'll bypass interlocks that prevent
17
But at this point there's really nothing
18
we can do to insert rods until those attachments are
19
in.
20
manually drive rods because, you know.
The scram signal's already there.
21
MR.
BROADBENT:
The
analysis
22
assumption is that you never get rods in.
It gets
23
shut down with the SLC.
24
MEMBER BROWN:
25
MR.
BROADBENT:
Right.
We can't
Okay.
And
you
saw
when
he
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1
initiated SLCs.
2
MEMBER BROWN: That was my question. It's
3
a later action manually taken to finally insert, pull
4
up, whatever the term is.
I'm a PWR guy --
5
(Simultaneous speaking.)
6
CHAIR STETKAR: Before -- I don't have any
7
questions on the simulation, but, you know, reducing
8
feedwater flows is a pretty standard ATWS response on
9
all boilers. What, now there's a magic 90-second time
10
window, and I wasn't here in the subcommittee meeting.
11
I'm not a boiler, thermal hydraulics, core neutronics,
12
anything guy.
13
window in the past to reduce feedwater flow?
14
15
MR.
LIDDELL:
Typically
two
to
three
minutes.
16
17
What was, did you have a nominal time
CHAIR STETKAR:
Two to three minutes,
okay.
18
MR. LIDDELL:
And the reason it took
19
longer, you're doing all the same actions but you're
20
three-parting just about every action and they're all
21
being done in sequence versus parallel.
22
VICE CHAIR BLEY:
23
difference
24
communication.
25
is
getting
MR. LIDDELL:
So that's the main
rid
of
the
That's right.
three-way
And allowing
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1
a couple of actions to be done in parallel versus
2
sequentially.
3
CHAIR STETKAR:
Okay, thank you.
4
MR. BROADBENT:
Okay.
And continuing on
5
with the presentation, there were a few requests from
6
the subcommittee.
7
associated with the TRACG Tmin and the underlying
8
bases
9
associated with PCT margin.
and
One on operator action times, one
references
10
and
all,
and
another
one
The staff, the NRC staff answered the
11
first one.
We'll let them discuss that in their
12
presentation.
13
response.
14
to get into the details with that we can do it in the
15
closed session.
The second one, we did provide a
We listened to references, and if you want
16
And then the third one was with regard to
17
PCT margin.
And talking about PCT margin, we, you
18
know, the ATWS-I and the ATWS analysis, their best
19
estimate
20
values in some of these sensitive inputs in the
21
analysis.
22
example, we assume a minimum core flow of 80 percent
23
which is the lower band of our window.
24
actually design the core all the way down that far, we
25
actually only design the core to 85 percent.
analyses,
In
we
three
do
apply
cases,
in
some
conservative
three
areas,
for
We don't
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1
So we used a nominal value and some of the
2
sensitivity evaluations of 85 percent.
3
with rod peaking.
4
that we're at 95 percent of the LHGR limit. We design
5
with ten percent margins, so we use the actual margins
6
for
7
transient that occurs in an ATWS, and we assumed a
8
bounding or a faster drop than expected.
9
our sensitivity evaluations we used a more realistic
10
LHGR.
Also
Same thing
The license basis analysis assumed
there's
a
feedwater
temperature
So we, in
value for that.
11
MEMBER BANERJEE:
So just before we go on
12
because this is interesting. Clearly when you look at
13
this you have to get some uncertainties because this
14
is a best estimate calculation.
15
MR. BROADBENT:
16
MEMBER BANERJEE:
That's right.
And so you have to put
17
some distributions and bounds on these parameters
18
which because you're sampling.
19
sampling of this to look at your uncertainties?
20
MR. BROADBENT:
So do you do the
I think that was part of
21
the RAI response where we described an evaluation that
22
had been performed.
23
GE numbers and then they generate a PCT trend.
24
25
For the actual analysis we give
MEMBER BANERJEE:
Well, they do a single
calculation.
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1
MR. BROADBENT:
Right, right.
2
MEMBER BANERJEE:
And you were appealing
3
to another calculation done for a different situation,
4
right?
5
MR. BROADBENT:
6
talk about that in the closed session.
7
8
That's right.
MEMBER BANERJEE:
We could
So we need to go into
that in some detail which you did.
9
MR. BROADBENT:
Okay.
Just some results
10
associated with this.
11
session with actual numbers on the y-axis, but this is
12
still a good comparison, where the red line is the
13
license
14
oscillations early due to the conservative assumptions
15
that we applied.
analysis
and
We have a graph in the closed
you
could
see
we
have
16
The green and the blue is where we use the
17
nominal assumptions, and with the blue we still assume
18
the 90-second operator response time, and you can see
19
that we barely saw any oscillations.
20
green we assumed 120-second operator response time,
21
and there were some oscillations but it was bounded by
22
the license basis case.
23
24
And with the
MEMBER BANERJEE: So what's the difference
between the red and the green and the blue?
25
MR. BROADBENT:
The red is the base case.
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1
That's our license basis analysis. That's the case GE
2
ran and the PCT trend that we saw.
3
that's in our MELLLA+ safety analysis report.
4
5
MEMBER BANERJEE:
difference?
6
Right.
7
things.
8
85 percent core flow.
Well, it was these three
We assumed, instead of 80 percent we assumed
MEMBER BANERJEE:
Oh, okay.
10
you going to be allowed to operate in?
11
MR. BROADBENT:
12
at 80 percent.
13
14
We can --
MEMBER BANERJEE:
That's the case that's
important, right?
MR. BROADBENT:
16
MEMBER BANERJEE:
Right.
You may want to do
something else, but yes.
18
19
But what are
We're allowed to operate
15
17
So what is the
What changed between these?
MR. BROADBENT:
9
That's the case
MR. BROADBENT:
And we're just trying to
show the sensitivity of that.
20
MEMBER BANERJEE:
Can you go back to that
21
slide please?
The previous one.
22
base case you're well into oscillations at 90 seconds.
23
MR. BROADBENT:
24
MEMBER BANERJEE:
25
MR. BROADBENT:
So if you ran the
Yes.
Okay.
And that's when we start
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1
to level everything.
2
3
MEMBER BANERJEE: But you stop the actions
no matter whether you're in oscillations or not.
4
MR. BROADBENT:
5
MEMBER BANERJEE:
6
MR.
7
Right.
BROADBENT:
Right,
they're
Yes,
they're
procedurally driven.
8
9
That's right.
MEMBER
BANERJEE:
procedurally driven.
10
MEMBER BALLINGER:
Now we can go into
11
this, I'm sure, in the closed session, but I'm looking
12
at the time scale. Is it physically possible for fuel
13
temperature, and I don't know what the left hand scale
14
is so --
15
16
MR. BROADBENT: We've got it in the closed
session.
17
18
MEMBER
BALLINGER:
This
is
a
calculation so --
19
MR. BROADBENT:
20
MEMBER REMPE:
21
Okay.
That's right.
So on the prior side you
said you removed some of these conservatisms.
22
MR. BROADBENT:
23
MEMBER REMPE:
open
session
which
Right.
Can you give us a feel in
24
the
of
25
removed had a larger impact?
the
conservatisms
you
Because as Sanjoy said
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1
you're allowed to operate in 80 percent.
2
one that really made the difference?
3
MR. BROADBENT:
Is that the
I'm not sure I know the
4
answer to that, which ones were the most important.
5
We can answer that.
6
7
And Mike, do you have a --
MR. COOK:
Hitachi.
This is Mike Cook from GE
Is this mic on?
8
MR. BROADBENT:
9
MR.
10
COOK:
Yes.
The
feedwater
temperature
response is probably the most important here.
11
MEMBER REMPE:
Thank you.
12
MEMBER BANERJEE:
And when you mean the
13
bounding faster drop, how much faster, or can you tell
14
us that here?
15
MR. BROADBENT:
16
MEMBER BANERJEE: Yes, okay. If you can't
17
answer these questions here.
18
19
So maybe we should --
MR. BROADBENT:
We can discuss them in
closed session.
20
MEMBER BANERJEE:
21
MR. BROADBENT: Significantly faster than
22
what we would expect.
23
about license conditions?
24
25
MR. NADEAU:
We need some numbers.
And Jim, do you want to talk
Thank you.
Time-critical
operator actions will be incorporated into our license
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1
conditions.
2
operators, the validation that they can all meet the
3
time-critical actions that we specified earlier, and
4
we
5
operating in the MELLLA region.
will
It will include the training of the
report
the
results
to
the
NRC
prior
to
Next slide.
6
So overall conclusion is Grand Gulf can
7
operate safely in the MELLLA+ region. We're confident
8
of that because we've got a good quality analysis,
9
we've got a good quality training program, and time-
10
critical operator actions will be met.
11
MEMBER SCHULTZ:
I thought there was a
12
condition related to single-loop operation.
13
no longer applied in the MELLLA+?
14
MR. NADEAU:
15
MR. FORD:
Is that
No, it's there.
We have a license condition
16
that says we can't operate in single-loop or loss of
17
feedwater or you're removed from service.
18
MEMBER SCHULTZ:
19
MEMBER BANERJEE:
Thank you.
Is that because, is
20
single-loop, generally single-loop operation is not
21
limiting with regard to stability, if I understand the
22
situations. So maybe I should ask the staff. Why is,
23
I mean generally it's the two RPT pump trip that gives
24
you the limiting conditions for stability.
25
MR. MARCH-LEUBA:
That is correct.
That
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1
will give you the worst transient.
2
MELLLA+
3
(phonetic) line, going into single-loop gets you in
4
the bottom of that MELLLA+ and we don't really want to
5
them to operate there.
6
for them to operate in MELLLA+ and single-loop.
domain
7
8
one
unit's
in
a
However, in the
such
high
home
So it would be very difficult
MEMBER BANERJEE:
Agreed, agreed.
Yes,
sure.
9
MR. MARCH-LEUBA:
So indeed it becomes
10
pretty handy, because the last incident that happened
11
last month was because single-loop operation.
12
was good foresight.
13
don't
14
requirement for it.
think
15
the
So it
And they don't need it and I
staff
would
MEMBER BANERJEE:
ever
release
that
And I guess they run
16
both transients and see, but usually it's the two RPT
17
which is limited --
18
19
MR. MARCH-LEUBA:
the flow.
Well, the RPT uses half
So yes, absolutely.
20
MEMBER BANERJEE:
21
MEMBER REMPE:
Right.
We're running a little bit
22
behind so I think we need to switch to the staff's
23
open presentation.
24
25
CHAIR STETKAR:
I just wanted to ask one
more question. Ricky, do you have a rough estimate of
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1
how many unplanned scrams you've had at Grand Gulf in
2
the last five years?
3
4
MR. LIDDELL:
We had five, I believe, the previous cycle.
5
6
We've had two this cycle.
CHAIR STETKAR: So you get a couple issues
though per cycle?
7
MR. LIDDELL:
8
CHAIR STETKAR:
9
MEMBER REMPE:
10
Yes.
Thanks.
That helps.
Can we move to the staff?
And thank you.
11
MR. A. WANG:
Good morning.
My name is
12
Alan Wang.
I'm the project manager for Grand Gulf
13
Nuclear Station.
14
already been gone over, so I'll just go to the second
15
slide.
I had two slides most of which has
16
So basically as discussed we do have two
17
license conditions as part of the approval for the
18
amendment.
19
the
20
requirements.
One is on the single-loop operation and
other
21
one
is
on
the
operator
training
There are three amendments tied to this
22
submittal.
Of the three, the most important is the
23
effective fluence in the MELLLA+ operation.
24
still staff review.
25
and we expect to finish the MELLLA+ amendment in June
That is
We expect to finish that in June
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1
also, by the end of June.
2
Safety Limit MCPR which had been increased for a
3
MELLLA+
4
completed.
operation.
5
The other two are the
That
safety
MEMBER BANERJEE:
evaluation
is
Is that because there
6
was some uncertainty in the power distribution, or
7
what was that increase?
8
9
MR. JACKSON:
Well, I think that the
applicant would be better off answering that. But the
10
Safety
Limit
11
depending on how you load the core or how you design
12
the cycle. So that MELLLA+ needs to come in 18 months
13
in advance, so it's not unexpected that we'd get the
14
Safety Limit MCPR.
15
It's finished.
16
line exactly with this one so that there's no --
17
18
MCPR
is
sort
cycle
dependent,
That amendment's been approved.
We're just making sure the SER is in
MEMBER BANERJEE:
So it's just a penalty
of some sort.
19
MR. JACKSON:
20
MEMBER BANERJEE:
21
of
Yes.
It's 0.02 or something,
what is it?
22
MR. JACKSON:
We were fined the penalty.
23
I have it on my desk, 0.02, because their power
24
density is greater than 42.
25
wasn't unexpected given that we get those six months
So I have that.
But that
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1
before the end of the cycle relatively routinely, so.
2
MR. A. WANG:
And then the last amendment
3
is they will be adding the DSSCD to their COLA as one
4
of the references that allow them to use DSSCD in
5
future
6
review for approval.
refueling
7
8
outages
and
won't
MEMBER BANERJEE:
require
staff
They're not already
using DSSCD?
9
MR. A. WANG: No, the MELLLA+ will approve
10
the use of DSSCD for the Grand Gulf Station, but the
11
amendment will add it to the COLA so for future
12
outages they can use the methodology without coming
13
back in for staff --
14
MR. JACKSON:
15
TRACG-04,
16
available to them if they want to use the more recent
17
approved version.
18
for --
19
so
they
have
DSSCD was updated to use
that
in
GSTAR
and
it's
And that's what they're looking
MEMBER BANERJEE:
They will want E1a, or
20
what do they, how were they operating the thing
21
before?
Were they in option 3 or --
22
MR. JACKSON:
23
MEMBER BANERJEE:
24
MR.
25
before.
JACKSON:
Yes.
They were in option 3.
They
were
using
DSSCD
They can use that with their current tech
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1
specs or with their currently approved because the
2
prior version of DSSCD is a GSTAR which is in their
3
tech specs.
4
TRACG-04 is not, so they want to incorporate that.
5
That review's been done.
6
There's no technical review associated with that. But
7
the technical review has been done and associated with
8
this MELLLA+ application.
9
for TRACG-04, the latest version's a good thing.
10
But the later version that incorporates
MEMBER
That of course applies.
So DSSCD is a good thing
BANERJEE:
I'm
just
trying
to
11
understand, when they went up to EPU level didn't they
12
start DSSCD at that point?
13
14
MR. JACKSON:
I don't think so.
I think
they --
15
MEMBER BANERJEE: They stayed in option 3?
16
MR. JACKSON:
17
Yes.
Can you confirm that
though?
18
MR.
BROADBENT:
Yes,
19
Broadbent with Entergy.
20
then for EPU we went to option 3.
21
for MELLLA+ we're going to DSSCD.
22
this
And then for this,
Okay, but you haven't
23
actually put the plant under DSSCD yet.
24
approved you will.
MR.
JACKSON:
Greg
We were E1a until EPU, and
MEMBER BANERJEE:
25
is
Once
this
Once this is
is
on
it's
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1
required.
2
3
MEMBER BANERJEE: It's not on. Everything
is there.
4
5
MR. A. WANG:
The hardware is there, it's
just not on.
6
MEMBER REMPE:
On the first one about the
7
fluence, during our subcommittee meeting I was left
8
with the impression that it was a sure bet that you
9
would have the amendment approved and that doesn't
10
sound so sure now.
11
Will you hold off on approving the MELLLA+ until it is
12
-- so could I rephrase what you're saying.
13
not if, it'll be both will be approved in June or both
14
will be approved whenever they both can be approved?
15
What would be the ramification?
MR. A. WANG:
You're right.
We will
The fluence
16
has to be approved first and then MELLLA+.
But we're
17
expecting to approve the fluence in June and then the
18
MELLLA+ will follow.
19
MEMBER REMPE: Thank you for clarifying.
20
MR. A. WANG:
21
And actually that's all we
had for the open for the staff.
22
MEMBER REMPE: So at this point we need to
23
stop and open the mics if there's anyone that has a
24
question from the public and allow anyone in the room
25
to come up with comments.
And comments from the
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1
public, not questions.
I should be more careful how
2
I word that. I assume since nobody's going to the mic
3
there's no one in the room that has any comments?
4
MR. W. WANG: The public line is open now.
5
MEMBER REMPE:
Okay.
Is there anyone out
6
on the line from the public that would just speak so
7
we know you're there?
8
MR. LEWIS:
9
MEMBER REMPE: Okay, thank you. Are there
10
My name is Marvin Lewis.
any comments from the public at this time?
11
(No response.)
12
MEMBER REMPE: And with that I think we'll
13
close the public lines and we'll go into closed
14
session.
15
to confirm that only those who are supposed to be here
16
are here.
And I'd like for the staff or the licensee
17
(Whereupon, the above-entitled matter went
18
off the record at 9:44 a.m. and resumed at 11:00 a.m.)
19
CHAIR STETKAR:
We are back in session,
20
and this is an open session so we have the bridge
21
line.
22
the public.
23
Guide 1.27, and Harold Ray will lead us through this
24
session.
I'm assured that we have a bridge line open to
25
And the topic of this session is Reg
So Harold, it's yours.
MEMBER RAY:
I had it right here in front
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1
of me ready to do that and failed.
2
CHAIR STETKAR:
3
MEMBER RAY:
Operator training.
Training again, yes.
I'm
4
glad that we have coaching when we need it.
5
Regulatory Guide 1.27, Ultimate Heat Sink for Nuclear
6
Power Plants, is being revised for reasons which will
7
be described by the staff during our presentation.
8
The pending revision, Revision 3, was
9
reviewed
by
the
Regulatory
Policy
and
Anyway,
Practices
10
Subcommittee on March 4th. At that time the staff had
11
resolved public comments and these were summarized as
12
part of the staff presentation.
13
Today the staff will also summarize their
14
resolution of comments and questions from members
15
received during the subcommittee meeting.
16
we've spent a good deal of time these days on a couple
17
of items that are not included in the Reg Guide
18
revision, I would like to mention these before the
19
staff begins.
20
Because
The first item not included is guidance
21
which
would
apply
22
designs.
23
attributes which have thus far been reviewed on a case
24
by case basis, to maintain clarity of the detail in
25
the Reg Guide it continues to be limited to active
Because
to
review
passive
of
passive
designs
have
reactor
unique
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1
plants use water as an ultimate heat sink.
2
The second item not included is accidents
3
resulting from beyond design basis events.
4
at a multi-unit site only one unit is assumed to be in
5
an accident condition.
6
have tripped.
7
indicated that guidance is being developed separately
8
by
9
action
10
JLD
Currently
Other units can be assumed to
At the subcommittee meeting the staff
staff
to
address
conditions
due
simultaneous,
to
a
beyond
multi-unit
design
basis
external events.
11
That concludes my initial remarks, and I
12
understand that Brian Thomas will start us with some
13
remarks.
14
MR. THOMAS:
Yes, good morning.
Brian
15
Thomas from the Division of Engineering in the Office
16
of Research.
17
gets going let me just say that indeed we're at the
18
Revision 3 version of the Reg Guide.
19
I'll just very briefly before the staff
This is a very old Reg Guide. It was last
20
revised back in 1976.
21
the
22
incorporating,
23
operating experience.
24
update Reg Guides on a regular basis.
25
you know, the Reg Guide update program was embarked
update
to
So basically the approach with
this
you
Reg
know,
Guide
the
has
last
to
40
do
years
with
of
The staff is committed to
Of course the,
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1
upon in a more focused manner back in 2006, of course
2
when the Commission directed the staff to do so. Of
3
course that was with the expectation of a renaissance.
4
So the Reg Guide update program, I would
5
say it's in full stride now in terms of regular
6
updates and periodic reviews of the Reg Guides.
7
staff has briefed the ACRS. It's the Regulatory Policy
8
and Practices Subcommittee as Harold said back on
9
March 4th.
The
10
The comments and the suggestions of the
11
ACRS members are incorporated into the Reg Guide
12
specifically with regard to some of the items such as
13
like to how to address this passive plant, so not
14
addressed in the Reg Guide but we have the appropriate
15
staff here to respond to some of those questions if
16
the committee has further questions.
17
18
So with that I'll turn it over to the
staff to make their presentation.
19
MR. LIN:
Thank you.
Okay, thank you, Brian, for the
20
introduction.
I'm Bruce Lin.
I work at Office of
21
Research Division of Engineering.
22
Jerry Purciarello with NRR Division of Safety Systems.
23
We appreciate the opportunity to brief the committee
24
on the proposed Revision 3 to Regulatory Guide 1.27.
25
This is an outline of what we plan to
With me up here is
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1
cover
today.
I'll
briefly
provide
you
with
an
2
overview of Reg Guide 1.27 and what's covered in the
3
Reg Guide and the purpose of the Reg Guide and the
4
reason for the revision, and also give you a high
5
level summary of the changes that were made in the
6
Revision 3.
7
He's going to talk about more details on the technical
8
changes that were made.
And then I'll turn it over to Jerry.
9
And also we're going to briefly touch on
10
the public comments. We don't plan to go into details
11
on the public comments since those were discussed in
12
length at the subcommittee meeting, but we did include
13
some
14
responds as the backup slides.
15
to address like Brian said and Jim and Ray said, we're
16
going to address some of the subcommittee comments in
17
this presentation.
of
18
the
significant
comments
and
the
staff
And then we're going
Just a little bit of background on what is
19
ultimate heat sink.
The ultimate heat sink is the
20
system of structures and components and associated
21
water supply that's credited for functioning as a heat
22
sink to remove reactor decay heats and essential
23
station heat loads after a normal reactor shutdown or
24
a shutdown after an incident.
25
necessary water retaining structures and the piping
This will include the
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1
systems that connect the water supply to the essential
2
cooling water intakes.
3
So essentially the UHS performs three
4
principal safety functions.
5
heat
6
residual heat after an incident such as a loss of
7
coolant incident, and also removal of the maximum
8
expected decay heat from the spent fuel pool.
after
reactor
Removal of the residual
shutdown,
dissipation
of
the
9
So this slide is just to provide a high
10
level overview of what's in Reg Guide 1.27. Basically
11
Reg Guide 1.27 provides methods and procedures that
12
licensees and applicants can use to establish the
13
ultimate heat sinks.
14
considerations for ultimate heat sinks such as the
15
safety feature you must perform, the heat loads to
16
consider
17
ultimate heat sinks, and in the Reg Guide we also
18
include meteorological conditions to consider in the
19
design of ultimate heat sinks.
20
when
It contains systems design
determining
the
performance
of
the
And there's also guidelines on how design
21
against natural phenomenons and site hazards.
22
also in the revision we added additional guidance with
23
respect to inspection and maintenance in testing of
24
ultimate
25
guidance for water chemistry and micro-bio control.
heat
sink
systems.
And
we
also
And
added
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1
So why are we updating this Reg Guide?
I
2
think it's obvious.
The first thing is because it's
3
outdated.
4
of things have changed and so we want to update the
5
Reg
6
operating experience in the last 40 years.
The last revision was January 1976.
Guide
to
incorporate
lessons
A lot
learned
from
7
And we also want to update the Reg Guide
8
so the guidance is consistent with the more current
9
NRC guidance such as the Standard Review Plan. And we
10
also want to include the changes that were made in the
11
regulations in the last 40 years such as we added the
12
maintenance
standards,
the
maintenance
rules.
13
So it's also a commitment from the staff
14
to, like Brian mentioned, to update the Reg Guides on
15
a regular basis to ensure that the guidance is current
16
and accurate.
17
This slide just provides a summary of some
18
of the changes that were made in the Rev 3.
19
introduction section we added additional rules and
20
regulations that were applicable to ultimate heat
21
sinks. For example, in the current revision they only
22
list GDC-2 protection against natural phenomenon and
23
GDC-44 cooling systems as applicable regulation.
24
Rev 3 we added several other GDCs such as GDC-45 for
25
inspection
of
water
cool
systems,
GDC-5
In the
in
In
the
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1
maintenance rules.
2
In the discussion section we revised and
3
added additional design considerations.
4
considerations in the discussion section are repeated
5
again in the regulatory position section which Jerry's
6
going to talk about.
7
Some
8
include
9
perform.
of
additional
the
Some design
considerations
safety
features
that
we
added
UHS
must
We added some guidance with respect to
10
performing transient analysis.
I think we clarified
11
some other issue with respect to our critical time
12
periods.
13
And in the regulatory position section we
14
made changes to the four existing regulatory positions
15
primarily to clarify some of the positions that were
16
confusing, and we also added several other additional
17
design considerations based on operating experience.
18
And
19
regarding inspections and maintenance of ultimate heat
20
sinks and micro-bio controls.
then
we
added
two
new
regulatory
positions
21
Jerry, do you want to take off from there?
22
MR. PURCIARELLO:
Regulatory
Guide
we
Yes.
Thanks.
have
four
In the
23
current
regulatory
24
positions, and in the new Regulatory Guide we maintain
25
those four positions with some changes and we've
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1
added, as Bruce said we've added two new regulatory
2
positions.
3
The first two regulatory positions we had
4
improvements and clarifications and we have some new
5
guidelines
6
regulatory position there's no change in content, we
7
just made some minor editorial changes, and then we've
8
added the fifth and sixth regulatory positions for
9
inspection,
10
in
there.
In
maintenance
and
the
third
water
and
fourth
chemistry
and
biological control.
11
In
Regulatory
design
Position
is
13
clarifications regarding the transient analysis.
14
added clarifications regarding whether you have, if
15
you have two cooling towers are more that you have to
16
include the effects of recirculation and interference.
17
And we also added clarification on how to
18
select critical meteorological data when computing
19
basically the real basic criteria for having ultimate
20
heat sink that is the maximum intake water temperature
21
to the plant and also the fact that it has to last for
22
30
23
considerations for fire resistance, about construction
24
materials having to be fire resistant.
25
We
then
added
also
the
added
added
on
system
And
we
which
12
days.
considerations,
1
system
requirement,
the
some
We
design
safety
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1
related requirement of being able to remove the heat
2
from the spent fuel pool.
3
criteria regarding the active components.
4
guidelines for manual actions if appropriate, but
5
we've
6
automatically operated.
said
7
that
the
And then we've added some
active
components
We added
should
be
And then we've added some criteria for the
8
inventory.
We want our licensees to include boundary
9
leakage because recently a licensee tried to exclude
10
boundary leakage when it was significant leakage and
11
said that the Reg Guide didn't cover that.
12
will.
So now it
Next slide please.
13
And then Regulatory Position 2 regarding
14
natural phenomena site hazards we made sure that the
15
site hazards were associated with GDC-2.
16
say GDC-2 before.
It didn't
17
And then we added clarifications regarding
18
the failure of manmade structures to include, we
19
expounded
20
reservoirs, dams, upstream and downstream dams, that
21
is, including potential for flow blockage by debris
22
based on industry experience.
23
features associated with the potential changes in the
24
ocean and river levels or lake levels, and that was
25
based on a public comment that we received.
upon
the
manmade
structures
to
include
And then also added
And then
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1
also based on experience we've added criteria for
2
adverse conditions associated with icing and freezing
3
of a water storage facility like the basin of a
4
cooling tower.
5
And
then
we
also
added
GDC-4
to
the
6
criteria for the ultimate heat sink that has to take
7
into account pipe whip, water hammer and any type of
8
dynamic effect.
9
experience we added the requirements that consider
10
potential clogging of the suction flow paths because
11
that's happened throughout the industry both here in
12
the United States and overseas.
13
And then also based on industry
Next slide please.
Okay, we've added, like I said before
14
we've
made
15
Positions 3 and 4, but I won't discuss those because
16
there's no content change to it.
17
Positions 5 regarding inspection, maintenance and
18
performance, this is based on current knowledge and
19
experience.
20
Regulatory Position for maintenance and inspection.
21
some
editorial
changes
to
Regulatory
But Regulatory
We decided that we had to add this
I
believe
there
was
cases
of
cooling
22
towers having excessive corrosion.
You might recall
23
back in 2006 a non-safety related cooling tower,
24
Vermont Yankee, actually collapsed.
25
cooling tower.
It was a wooden
Non-safety, it wasn't involved in the
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1
ultimate heat sink but that was a consideration for
2
including this regulatory position for inspection,
3
maintenance and performance testing.
4
And then we've added also the criteria
5
that if the dam or water control structure is within
6
the jurisdiction of the licensee that it should be in
7
the
8
maintenance rule.
maintenance
program,
Reg
Guide
1.160,
the
9
And then Reg Guide 1.27 we added since the
10
subcommittee, and that's actually for inspection of
11
all water control features or structures whether it's
12
under the jurisdiction of the licensee or not within
13
the jurisdiction of the licensee.
14
MEMBER
SCHULTZ:
Jerry,
is
Reg
Guide
15
1.127, is that a relatively new Reg Guide? Or if not,
16
is it recently updated?
17
MR. LIN: This Reg Guide is out for public
18
comments. I think it's due currently out for public
19
comments. It was issued January 2015 out for public
20
comment.
21
22
MEMBER SCHULTZ:
it's in.
Okay, that's the stage
Thank you.
23
MR. LIN: The current version is very old.
24
MR. PURCIARELLO:
25
MEMBER SCHULTZ:
1978.
Thank you.
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1
MR. PURCIARELLO: And then we felt the need
2
to
add
Regulatory
3
knowledge
4
chemistry and microbiological control. Next slide
5
please.
and
6
Position
experience
and
6
based
that
on
current
involves
water
And in the Reg Guide we've, as the slide
7
says the draft Reg Guide was published in 2013.
We
8
received comments from the public, ten from NEI, and
9
some from the general public and anonymous also.
10
We've resolved those comments and we put those in Reg
11
Guide 1.27 as appropriate.
12
We had our subcommittee meeting back in
13
March and -- next slide please -- and the subcommittee
14
had some comments that I'm now going to address.
15
The subcommittee took exception to the
16
phrase "reasonably to be expected" because they wanted
17
some more specific criteria just as far as regards to
18
natural phenomena and site hazards.
19
I don't know if you're aware, but back in
20
2012
there
was
a
NUREG
published,
2150.
Is
the
21
committee aware of that? I don't know. But it involved
22
a proposed risk management regulatory framework and it
23
was commissioned by then Chairman Jaczko and chaired
24
by Commissioner Apostolakis. It was again it was a
25
proposed risk management regulatory framework.
And
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1
I'm reading from the executive summary here.
2
One of their findings was that the process
3
for establishing the external hazard design bases does
4
not
5
methods.
6
should reassess methods used to estimate the frequency
7
and magnitude of external hazards and implement a
8
consistent process that includes both deterministic
9
and PRA methods.
use
consistent
event
frequency
or
magnitude
And the recommendation for that was the NRC
Considerations of the risks from
10
beyond design basis events for external hazards should
11
be
12
category.
included
in
the
proposed
design
enhancement
13
So I guess to summarize that, what this
14
study found that we really don't have any specific
15
criteria for putting in some type of, you know,
16
frequency or expected assessment of magnitude methods
17
or frequency of any type of external design hazards.
18
So we can't get more specific than that.
19
So what we suggest using is taking out the
20
reasonably expected
21
uses and use the term "more appropriate combinations"
22
as opposed to reasonably expected.
23
we can't get any more specific than that. I think the
24
staff or the NRC recognizes that this is an issue and
25
that
somehow,
you
phraseology and using what GDC-2
know,
I
don't
And at this time
know
what
the
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1
corrective
2
implemented, but we don't have any way of becoming
3
more specific as far as talking about the magnitude
4
and the frequency of external hazards.
5
6
action
is
and
MEMBER RAY:
when
this
will
be
You are referring to these
other Reg Guides?
7
MR. PURCIARELLO:
Yes, and that's been
8
mentioned as far as for seismic and for hurricanes.
9
Yes, that's now in the Reg Guide.
10
CHAIR STETKAR:
Jerry, now if this Reg
11
Guide uses the term "appropriate combinations," does
12
that mean the onus on the staff and a particular
13
licensee to justify what is an appropriate combination
14
for their site?
15
MR. PURCIARELLO:
16
CHAIR STETKAR:
17
MR. PURCIARELLO:
I would say yes.
Okay.
I mean hopefully there
18
will be some guidance based on deterministic methods
19
and PRA that will come out sometime in the future that
20
would be more --
21
CHAIR STETKAR:
assessment
22
risk
23
criteria in the context of risk assessments.
24
that's
25
specifically
one
branch
I know in Research, the
issue
is
that
screening
looking
they're
criteria.
at
screening
looking
And
at
again
And
is
it's
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1
focused
in
the
2
necessarily
3
Regulatory Guide.
context
something
of
that
risk
would
assessment,
fall
into
not
this
4
But as you mentioned they are related in
5
sense because there is a frequency and there's a
6
compounding effect, you know, of certain types of
7
hazards.
8
how appropriate combinations would be considered, you
9
know, among the staff and the licensee if a particular
10
licensee came in and said, well, you know, I want to
11
make a change to something.
So I just wanted to make sure I understood
12
MR. PURCIARELLO:
Well, we used a higher
13
tier document and that is GDC-2.
14
word of that and you can't get any more specific than
15
that at this time.
16
MR. LIN:
We just used the
I know for specific hazards
17
there are standards that, I'm aware of a flooding.
18
There's
19
combinations for combined events.
an
ANS
standard
that
lists
appropriate
20
CHAIR STETKAR: Core flooding is, flooding
21
a bizarre issue that's being addressed a lot under,
22
external flooding anyway which we're concerned about
23
your being addressed under post-Fukushima initiatives.
24
MR. PURCIARELLO: Next slide please. This
25
slide
shows
one
of
the
subcommittee's
comments
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1
regarding the word "prudent."
2
didn't
3
subjective.
4
inspecting dams and water control structures that are
5
outside the jurisdiction of the licensee or applicant.
6
So as we previously stated on another
7
slide before this, we've added Regulatory Guide 1.27,
8
"Inspection of
9
with Nuclear Power Plants" to be used. We should have
seem
to
have
much
The word "prudent"
meaning
to
it,
very
This is in regards to the prudency of
Water Control Structures Associated
10
had this before.
11
trying to answer this subcommittee comment that water
12
control structures, dams included, should be under the
13
guidance of Reg Guide 1.27 for whether the structure
14
is controlled by the licensee or not by the licensee.
15
16
I guess we became more aware of it
MEMBER RAY:
change.
I think this is a good
The prudent part was troublesome to me.
17
MEMBER
RICCARDELLA:
yesterday
about
the
We
use
of
had
some
the
words
18
discussion
19
"should" and "shall" and "may" in documents such as
20
this.
Is the "should" appropriate here?
21
MEMBER RAY:
I believe so.
Another word
22
you might choose is "must," but I don't think that's
23
appropriate
24
equivalent, synonymous with "must," I think.
25
think regulatory guidance, "should" is appropriate.
for
regulatory
guidance.
"Shall"
is
But I
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1
That's my judgment.
2
MR. PURCIARELLO:
They're not required to
3
comply with this. If they come up with an alternative
4
that's acceptable to the staff they can deviate from
5
a guideline.
6
They can't deviate from a regulation.
CHAIR STETKAR:
I'm a little bit, I'm
7
looking at some notes.
8
on Reg Guide 1.127 and I don't remember what it was.
9
I guess my notes are from February of 2012.
10
We had a subcommittee meeting
And it
seemed to be some fuzziness in that Reg Guide.
11
Now you pointed to that Reg Guide for
12
inspection requirements, so I'm trying to close the
13
loop here.
14
Reg Guide how would the inspection apply to owners and
15
operators of upstream dams that were not part of the
16
licensee's
17
responses to well, you know, the NRC inspects some
18
nuclear power plant dams.
19
nuclear power plant dams.
And when we asked in the context of that
organization,
and
then
I'm
reading
The licensees inspect some
20
But the scope of that particular Reg Guide
21
does not include upstream dams whose failures may
22
cause flooding at the site unless those dams are also
23
required for heat sink retention. So it says -- these
24
are my notes.
25
itself. From my notes from the staff back in February
This is not a quote from the Reg Guide
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1
2012,
it
says
the
NRC
and
licensees
rely
on
2
inspections by other state and federal agencies for
3
those dams.
4
The concern obviously is if you have an
5
upstream or downstream dam outside of your control as
6
a licensee what assurance do we have indeed that those
7
dams are being inspected?
8
necessarily that pointing from this Reg Guide to
9
1.127, which hasn't been issued yet, but pointing to
And it's not clear to me
10
that solves the necessary concerns.
11
because I just want to point to some other guidance.
12
MR. PURCIARELLO: Can I read what this Reg
13
So that's a few
Guide 1.127 says?
14
CHAIR STETKAR:
15
MR. PURCIARELLO:
16
CHAIR STETKAR:
17
MR. PURCIARELLO:
18
CHAIR STETKAR:
19
MR. PURCIARELLO:
applies
to
Yes.
Or 1.27?
1.127.
Okay, good.
Okay.
control
Thanks.
It says, "This
20
guide
21
example,
22
specifically built for use in conjunction with the
23
nuclear power plant and whose failure could cause
24
radiological
25
public health and safety."
dams,
water
1.127?
reservoirs,
consequences
structures,
conveyance
adversely
for
facilities
affecting
the
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1
So in other words I read that to mean that
2
the dam has to be built in conjunction with the
3
nuclear power plant.
4
think a licensee can just, or an applicant can just
5
say I want to use that dam.
6
built in conjunction with the nuclear power plant.
7
No, it just can't be, I don't
The dam has got to be
In addition -- I'm reading again.
In
8
addition, the structure was built wholly or in part
9
for the purpose of controlling or conveying water for
10
either emergency cooling operation or flood protection
11
of the nuclear power plant.
12
MEMBER RAY:
Let me interject something
13
here.
When I read what you had done recognizing what
14
Chairman Stetkar just said and recalling that, I
15
thought you were referring to details on inspection
16
and performance monitoring meaning the methodology as
17
opposed to this describes an existing requirement.
18
I'm speaking of 1.127.
Trying to say it
19
another way, and I'm going to ask again is this your
20
intent. I thought this was a vehicle for defining how
21
to as opposed to saying, oh by the way this describes
22
what you must do.
23
said which is that the "should" is what's being
24
created in this Reg Guide or exists in this Reg Guide,
25
not the "should" doesn't come from 1.127 when we're
And that goes back to what Pete
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1
talking about what you're talking about here.
2
just the methodology.
3
MR. LIN:
It's
Now that was my reading of it.
I think with the intent of the
4
staff with the first sentence basically tell you, you
5
should
6
changes in structure, hydraulic and foundations, and
7
then we refer to the Reg Guide for specific guidance.
8
And also I'm reading from the draft.
inspect
9
the
water
MEMBER RAY:
control
structures
for
You're not inspecting by the
10
way, excuse me, you're not inspecting on the basis of
11
verifying the adequacy but you're looking at changes.
12
MR. LIN:
Right.
13
MEMBER RAY:
14
MR. LIN:
Okay.
Also in the draft, changes to
15
Reg Guide 1.127, basically it states that embankments
16
and other appurtenant structures associated with or
17
part of water control structures addressed by this Reg
18
Guide are those typically built to provide and protect
19
ultimate heat sinks.
It's in there.
20
So I think it's appropriate to --
21
MEMBER RAY: But again the Reg Guide 1.127
22
we understand is more constrained than would encompass
23
a dam failures which could result in flooding, which
24
is
25
constrained. It's talking about things that have been
what
we're
talking
about
here.
It's
more
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1
built to provide for the ultimate heat sink as opposed
2
to things that could fail and result in not the loss
3
of the ultimate heat sink but flooding.
4
Sherman was asking about I thought.
5
CHAIR STETKAR:
It's both.
That's what
I hate all of
6
this pigeonholing of things because people think about
7
flooding as some rise of water level.
8
dam failure as causing a mountain of water coming down
9
through some valley.
I think of a
That mountain of water will
10
allow level to rise, it also might sweep away things
11
like your intake structure.
12
intake structure with things like, oh, whatever towns
13
were upstream.
It also might clog your
14
So I don't want to get into this argument
15
about whether it's a dam failure that causes a flood
16
which triggers certain things or a dam failure that
17
might drain away an ultimate heat sink which would be
18
a downstream dam.
19
that may affect the site, the ultimate heat sink and
20
the intake structure being part of that site.
I'm concerned about dam failures
21
MEMBER SCHULTZ: What I've heard, John, is
22
you introduced this by saying we want to check and see
23
that the loop was closed.
24
that the loop is very small and incorporates what has
25
been established as the ultimate heat sink and what
And what I'm hearing is
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1
structures were used to do that.
It doesn't do what
2
you're describing and that is examine structures that
3
may affect the site and the ultimate heat sink beyond
4
that.
And so we just need to recognize that.
5
CHAIR STETKAR:
Yes.
And I don't know
6
what the context.
7
is focused on the ultimate heat sink might not be the
8
vehicle.
9
sure that we understand that distinction.
10
11
I mean, you know, 1.27, because it
It might be 1.127.
MEMBER RAY:
But we just need to make
Yes, I think that's a good
point.
12
MR. LIN:
I think Regulatory Position 2
13
restates that ultimate heat sink should be capable of
14
withstanding the failure of reservoirs, dams, and
15
other manmade water retaining structures both upstream
16
and downstream. And we're referring to this Reg Guide
17
for the routine inspection programs.
18
CHAIR STETKAR:
The only question is how
19
far upstream does that zone of influence extend?
20
Because in a very narrow interpretation of 1.127 it
21
extends only to the dams that were built for the
22
purpose of that nuclear power plant.
23
extend to the other dams that might be withholding,
24
you know, the greater portion of the watershed of, you
25
know, 50,000 square miles or something like that.
It doesn't
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1
MEMBER RAY:
Yes.
No, I think that's a
2
good point and it's clearly the case that this 1.27
3
isn't attempting to speak to the larger issue that
4
you've
constrained
by
5
apparently the limits that we've talked about.
I
6
think perhaps we have a larger concern that we need to
7
track going forward. I'm not wanting to dismiss it at
8
all.
described.
1.127
also
is
9
CHAIR STETKAR: We've addressed what would
10
link into some of the post-Fukushima flooding stuff
11
also, so we have that thing.
12
MR. PURCIARELLO: Next slide, please. And
13
then another issue was the issue of the design of
14
active components in the ultimate heat sink and that
15
we say that they should be automatically start or
16
open/close automatically by design.
17
There was some confusion in the last, at
18
the subcommittee meeting on whether when we refer to
19
manual action was it because the automatic features
20
failed or because they weren't designed into the
21
system.
22
component it should operate automatically per design
23
and then if it doesn't obviously it has to be operated
24
manually, and that's subject to Reg Guide 1.62 which
25
is on Manual Initiation of Protective Actions and that
And we're saying that if it's an active
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1
the manual actions will be judged by the staff on
2
whether it's allowed in that application for operation
3
of the UHS.
4
CHAIR STETKAR:
I think also during the
5
subcommittee meeting we mentioned that in general --
6
previous session I kind of made this point, but it was
7
a closed session so I'll do it again in an open
8
session. That the guidance for evaluating feasibility
9
and associated uncertainties with manual actions has
10
kind of evolved over time.
11
And
some
of
the
best
guidance
in
my
12
opinion anyway is NUREG 1852.
Now people will say,
13
well that has the word "fire" in the title of it, but
14
it's actually the basic concept of how you look at how
15
much time is available, how much time is required to
16
perform an action.
17
So if you have 60 minutes is available and
18
it takes 59 minutes to perform the action that gives
19
you one minute of margin and then there's uncertainty
20
about that.
So you look at the feasibility in the
21
context
time
22
uncertainties in both of those parameters and then
23
look at the margins. That concept is not in Reg Guide
24
1.62.
25
of
available,
time
required
and
We made comments on that when we had our
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1
subcommittee
meeting
on
Reg
Guide
1.62
current
2
revision back in, my notes are February, no, it was
3
even December of 2009.
4
NUREG 1852 was issued.
That was a couple years after
5
So I think some of the comments we had at
6
the subcommittee meeting is this assessment of the
7
feasibility of these manual actions perhaps ought to
8
be thought of in that context rather than the more
9
deterministic prescriptive context of Reg Guide 1.62.
10
MEMBER RAY: The example, and it's just an
11
example, John, of course here is make-up water, which
12
presumptively not guaranteed but presumptively time
13
isn't an issue.
14
But that's just an example.
CHAIR STETKAR: That's just an example and
15
that doesn't change the way you think about it.
I
16
mean providing the fact time is an issue because
17
eventually you're going to run out of water and you
18
have a certain make-up rate and a certain, you know,
19
use rate, and who knows, you know, how long.
20
simply pushing a button to start a pump that's one
21
thing. But that doesn't change the concept of the way
22
you think about it.
23
demonstrate feasibility using that methodology.
24
doesn't say that you ought not to think about the
25
methodology. And as you said that's only one example.
If it's
I mean it might be very easy to
That
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1
MEMBER RAY:
It is just one example.
I
2
guess the premise is as I looked at this anyway, was
3
that the license design rather than this Reg Guide
4
determined what needed to be automatic and what could
5
be manual.
6
that choice.
7
be made at some point and it needs to take into
8
consideration --
9
And that this wasn't attempting to make
You're pointing out that choice has to
CHAIR STETKAR:
I think the observation
10
was that some plants rely on operator, you know,
11
manual operator actions.
12
failure of an automatic function. This clarifies that
13
specific uncertainty.
14
rely
15
replenishment
16
another supply.
17
know, I'm not familiar with every plant.
18
MR. PURCIARELLO:
on
operator
of,
That it's not a backup to,
But some plants, you know, do
actions
you
for,
know,
a
one
closed
There could be others.
action
basin
is
from
I don't, you
Let me give an example.
19
How about a safety related cooling tower where the
20
fans
21
particular case, if they came in with a design that
22
the
23
wouldn't approve that.
24
get water up to the cooling tower that would not be
25
approved unless it's -- so we're saying in the Reg
have
to
operator
start
would
right
away?
manually
start
Well,
those
in
that
fans
we
Or if a valve has to open to
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1
Guide, and it's a guidance only. It's not saying that
2
they should start automatically.
3
The case of the make-up water obviously,
4
you know, that's a long term effect and we have no
5
problem, you know, if that's going to be done a couple
6
days
7
replenish water.
8
it doesn't last 30 days then they have to replenish
9
and it's not going to be right away, that would be a
10
manual action that would be, you know, acceptable.
11
And
some
are
context
12
something
has
to
13
automatic.
from
14
after
the
accident
have
to
It's supposed to last 30 days.
If
to
start
that
that.
or
CHAIR STETKAR:
they
We're
isolate
it
saying
if
should
be
No, I understand that.
15
What I'm talking about is the principle.
You're
16
saying manual.
17
guidance for manual initiation of protective actions,
18
and I'm saying that that Reg Guide is out of date
19
compared to the way that we think about demonstrating
20
feasibility of those actions.
21
MR. PURCIARELLO:
You know, the Reg Guide provides
Okay, then maybe we
22
should just take that out then. Are you suggesting we
23
should take that, we could take it out.
24
25
CHAIR
STETKAR:
Not
a
role
as
an
individual member of the ACRS to necessarily suggest
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1
the wording, I'm just trying to alert you to the fact
2
that there's kind of an evolving notion of how one
3
demonstrates feasibility of these manual actions. And
4
that Reg Guide 1.62, at least the latest version I
5
have, was a snapshot of that in 2010.
6
we had comments on that Reg Guide at that time, but
7
unfortunately they were ignored.
8
9
MR. PURCIARELLO:
would be appropriate here.
11
CHAIR STETKAR:
decision.
13
14
We did ask our human
factors engineers here, and they said Reg Guide 1.62
10
12
And as I said,
Okay.
And that's your
Thanks.
MR. PURCIARELLO:
Next slide, please.
Then the last issue --
15
CHAIR STETKAR: Jerry, just one thing. Be
16
careful of those papers.
17
they're really sensitive.
18
Once we have the mics on
MR. PURCIARELLO:
Sorry.
The last issue
19
we're going to talk about now is addressing the final
20
subcommittee comment regarding the applicability to
21
passive plants. And the staff concluded that this Reg
22
Guide should apply only to plants with active safety
23
systems for the reasons stated there.
24
you know, that passive plants are judged on a case by
25
case basis and it doesn't appear to be beneficial to
That's there,
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1
develop a Regulatory Guide for passive plants at this
2
time.
Okay, next slide please.
3
So in conclusion, this Reg Guide has been
4
revised to address current regulations and lessons
5
learned from operating experience.
6
necessary
7
ultimate heat sink.
8
and ACRS comments and we've incorporated comments
9
appropriately, and we believe that Reg Guide 1.27 is
10
for
a
licensee
to
design
an
We've reviewed public comments
now ready for final publication.
11
12
guidance
It provides the
MEMBER RAY: Are there other questions for
staff from members?
13
MEMBER SKILLMAN:
Harold, this is Dick.
14
MEMBER RAY:
15
MEMBER SKILLMAN:
Yes, go ahead, Dick.
Staff, thank you for
16
presentation. We'd just like to suggest on your draft
17
Reg Guide, Rev 3, Page 4, top paragraph described in
18
the last sentence, heat of the spent fuel pool.
19
know a number of plants in the country actually have
20
pools, plural, and that would be my only comment.
21
MEMBER RAY:
22
MEMBER SKILLMAN:
convinced
me
on
I
Thank you, Dick.
the
Yes, sir.
And Harold
23
you
appropriateness
of
not
24
attempting to combine passive and not passive. So I'm
25
with you.
Thank you.
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1
MEMBER RAY:
Thank you.
Anything else?
2
I believe the phone line is now open and so we invite
3
any comments from members of the public who have been
4
listening in.
5
in good time, Mr. Chairman.
6
Hearing none, I'll turn it back to you
CHAIR STETKAR:
And I am duly impressed
7
and thankful.
I'd like to thank the staff and also
8
thanks for taking our comments from the subcommittee
9
at heart.
We appreciate that.
That's one of the
10
reasons why we have the subcommittee meetings to try
11
to get some of that input.
So thank you very much.
12
If nothing else, we are in fact recessed
13
for lunch and we come back to work on our own reports.
14
We don't have anything else on our agenda.
15
For the purposes of anyone who might be on
16
the bridge line, our agenda had one more topic listed
17
today and that was, look for the title because I can't
18
remember anything.
19
Reactor Oversight Process.
20
because of Member Skillman's illness, and we will
21
reschedule that for a later full committee meeting.
22
So we are now done with our formal presentations and
23
we are recessed for lunch.
24
25
Well, it's the update on the
We had to postpone that
Come back at 1 o'clock.
(Whereupon, the above-entitled matter went
off the record at 11:45 a.m.)
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MELLLA+
Grand Gulf Nuclear Station
Maximum Extended Load Line Limit
Analysis Plus
Advisory Committee on Reactor
Safeguards
Grand Gulf Nuclear Station
Maximum Extended Load Line Limit
Analysis Plus (MELLLA+)
May 7, 2015
2
Entergy ACRS Committee Presenters
•
Bryan Ford– Sr. Manager, Fleet Regulatory
Assurance Entergy
•
Greg Broadbent– Supervisor, Fleet Nuclear
Analysis Entergy
•
James Nadeau – Manager, GGNS Regulatory
Assurance Entergy
•
Ricky Liddell – Supervisor, GGNS Operations
Training Entergy
3
AGENDA
•
Overview and Benefits
•
Safety Analysis Methods
•
Simulator Video
•
ATWS-I Analysis
•
License Condition
4
Grand Gulf Nuclear Station Overview
• Operating License Issued November 1, 1984
• Commercial Operation Began July 1, 1985
• GE BWR 6 - Mark III Containment
OLTP Limit
3833 MWt
CLTP Limit
4408 MWt
• MELLLA+ Offers Improved Operational
Flexibility
– Reduced Reactivity Manipulations
– Reduced Operator Challenges
– Reduced Enrichment Requirements
5
Proposed Extended Operating Domain
6
Safety Analysis Methods
• Met all 80 Limitations and Conditions
–
–
–
–
Methods LTR NEDC-33173 (24 Limitations)
MELLLA+ LTR NEDC-33006 (52 limitations)
DSS-CD LTR NEDC-33075 (4 limitations)
TRACG LTR NEDC-33147 (0 limitations)
• Two Audits:
– GEH April 2014
– GGNS October 2014
7
GGNS-Specific Evaluations
ATWS Analysis
Evaluation of MELLLA+ LTR NEDC-33006P-A
– Operation in the MELLLA+ Region Results in a Higher
Power Level in the Event of an ATWS
– Operator Action to Initiate Reduction of Reactor Water
Level Within 90 Seconds of ATWS Identification
8
ATWS Time Critical Operator Actions
TCOA
MELLLA+
Initiate Reactor Water Level
Reduction
90 Seconds
Initiate Standby Liquid Control
Injection
300 Seconds
Initiate Suppression Pool Cooling
660 Seconds
9
Simulator Video
– Audit confirmed time to initiate water level
reduction was less than 90 seconds.
– Benchmark of Monticello confirmed that
Operators can initiate within 90 seconds.
– Operator Training Programs and initial actions
are comparable.
10
ACRS Sub-Committee Requests
• Operator Action Times
• TRACG Tmin (minimum stable film
boiling temperature)
• Peak Cladding Temperature Margin
11
ATWS-I PCT Margins
• ATWS-I Analysis is best-estimate
• GGNS runs applied conservative values in
some sensitive inputs
• Minimum core flow
– Assumed 80% although the core is designed with
85%
• Rod peaking
– Assumed on 95% LHGR limit although the core is
designed with >10% margin
• Post-ATWS Feedwater Temperature Transient
– Assumed bounding (faster) drop than expected to
increase reactivity insertion
– Sensitivity evaluations were prepared to quantify the
margin
12
Margin Analysis
Peak Cladding Temperature
Results of Sensitivity Runs
13
License Condition
• License Condition to Ensure Time
Critical Operator Actions
– Validation of Time Critical Actions Will
Confirm Crew’s Ability to Perform
– Results Will Be Reported to NRC
14
Conclusions
• GGNS Can Operate Safely in the
MELLLA+ Region
– Quality of Analysis
– Quality Training
– Time Critical Operator Actions Will Be Met
15
Regulatory Guide 1.27
Ultimate Heat Sink for Nuclear
Power Plants
(Revision 3)
Bruce Lin
RES/DE/CIB
Jerry Purciarello
NRR/DSS/SBPB
ACRS Full Committee Meeting
May 7, 2015
Agenda
•
•
•
•
•
•
•
Overview of RG 1.27
Reasons for Revision
Summary of Revisions
Technical Revision
Addressing Public Comments
Addressing ACRS Subcommittee Comments
Conclusions
Overview of RG 1.27
• The ultimate heat sink (UHS) is the system of structures and
components and associated water supply credited for
functioning as a heat sink to absorb reactor residual heat and
essential station heat loads after a normal reactor shutdown
or a shutdown following an accident or transient including a
loss-of-coolant accident (LOCA)
• The UHS performs three principal safety functions:
– Dissipation of residual heat after reactor shutdown
– Dissipation of residual heat after an accident such as a loss-of-coolant
accident
– Dissipation of maximum expected decay heat from the spent fuel pool
3
Overview of RG 1.27
• Describes applicable rules and regulations related to
UHS
• Contains systems design considerations for UHS
– Provides meteorological conditions considered in the design of
UHS
• Contains natural phenomena and site hazards design for
the UHS
• Provides guidance for inspection, maintenance and
system performance testing
• Provides guidance for water chemistry and micro-bio
control
4
Reasons for Revision
• Outdated
– Last revision: January 1976
• Need to update RG 1.27
– New reactor applications
– Revisions in regulations
– Lessons learned from operating experience
• NRC Staff Commitment to Commissioners in 2006
(ML060760667)
– Update RGs where appropriate to go along with the SRP update
associated with new reactor applications
– Commitment to update RGs on a regular basis
5
Summary of Revisions
• The introduction section was revised to include
applicable rules and regulations
• The discussion section was revised to incorporate/update
relevant design considerations for UHS
• Changes to the 4 existing regulatory positions and added
two new regulatory positions
6
Summary of Revisions
Regulatory Position (1976)
Regulatory Position (2015)
1. System design and
meteorological conditions
1. System design and
meteorological conditions
2. Natural Phenomena-hazards
2. Natural Phenomena-hazards
3. Defense-in-depth
3. Defense-in-depth
4. Technical Specifications
4. Technical Specifications
5. Inspection, maintenance, &
testing
6. Water Chemistry and Micro-bio
controls
7
Technical Revision
Regulatory Position (RP)1 – System Design Considerations for the UHS
• Added clarifications regarding transient analysis for UHS where the
water supply may be limited
• Clarified the critical time periods and the bases and procedure used
to select critical meteorological data
• Added the following systems design considerations:
– Construction material should be fire resistant
– Heat load that are important to safety should be included in determining the UHS
thermal performance (spent fuel pool)
– UHS active mechanical component should automatically start to support DBA
heat loads
– UHS inventory to support 30 day period for UHSs should account for potential
water losses
8
Technical Revision
Regulatory Position 2 – Natural Phenomena and Site Hazards
• The UHS should be capable of withstanding the most severe natural
phenomena expected at the site in accordance with GDC 2
• Added clarifications regarding failure of manmade structural features
• Added the following site hazard design considerations:
– Potential changes in ocean, river, or lake levels
– Potential for adverse environmental conditions such as icing and freezing of the
UHS water storage facility
– The effects of pipe whip, jets, energy line breaks and dynamic effects
– Potential clogging of suction flow paths
9
Technical Revision
RP 5 – Inspection, Maintenance, and Performance Testing (new)
•
Inspection and maintenance program should be established for the UHS system
piping, structures, and components (detection of corrosion, erosion, protective coating
failure, silting, and bio-fouling).
•
Dam or other water-controlling structure and connecting piping systems within the
jurisdiction of the licensee should be included in the Structures Monitoring Program in
accordance with RG 1.160 and the Maintenance Rule. RG 1.127, “Inspection of
Water-Control Structures Associated with Nuclear Power Plants” provides more details
on inspection and performance monitoring of water-controlling structures.
RP 6 – Water Chemistry and Microbiological Control (new)
•
The quality of the water used in cooling towers, spray ponds, and heat exchangers
should be considered in the design and operation of the UHS.
•
Redundant and infrequently used cooling loops should be flushed and flow tested
periodically at the maximum design flow to ensure that they are not fouled or clogged.
10
Addressing Public Comments
• The draft RG (DG-1275) was published for public comment
September 2013
• Comments received from:
– NEI (10), General Public (1) & Anonymous (2)
• The comments were evaluated by the staff and incorporated into the
draft RG 1.27, revision 3, as appropriate
11
Addressing Subcommittee Comments
•
When describing natural phenomena and site hazards, the RG uses terms such
as “reasonably be expected to occur during the plant lifetime” and “reasonable
probable combinations of less severe natural phenomena”. The ACRS
questioned this terminology as too vague and asked the staff to look into
screening criteria for external hazards
•
Proposed Staff Response:
– NUREG 2150,” A Proposed Risk Management Regulatory Framework,” dated April
2012 found: The processes for establishing the external hazard design bases do not
use consistent event frequency and magnitude methods and recommended that the
NRC should reassess methods used to estimate the frequency and magnitude of
external hazards and implement a consistent process that includes both deterministic
and PRA methods.
– The staff has decided not to include screening criteria for external hazards in RG
1.27. Appropriate guidance and criterial can be found in other RGs such as RG 1.59
“Design Basis Flood for Nuclear Power Plants” for flooding and RG 1.221 “DesignBasis Hurricane and Hurricane Missiles for Nuclear Power Plants” for hurricane wind
speeds or when the recommendations of NUREG 2150 are implemented.
– The staff proposes to delete “reasonably be expected” and to replace “reasonable
probable combinations” with “appropriate combinations”. The use of the term
“appropriate” is consistent with the terminology used in GDC 2.
12
Addressing Subcommittee Comments
• In the discussion, the RG states that “it would be prudent for licensee
to ensure other water controlling structures affecting the safety of the
site are being monitored under another program such as…” The
ACRS questioned the use of the word prudent rather than saying
something stronger such as the measures being applied to these
other structures.
• Proposed Staff Response – The staff has revised the sentence to
read “Inspection and monitoring of dam or other water control
structure should be conducted to ensure that changes in structural,
hydraulic, and foundation conditions can be detected. Regulatory
Guide 1.127, “Inspection of Water-Control Structures Associated with
Nuclear Power Plants” provides more details on inspection and
performance monitoring of water-controlling structures.”
13
Addressing Subcommittee Comments
• In Regulatory Position 1.j, with respect to auto start of mechanical
component, the sentence is confusing, more guidance should be
provided regarding operator actions.
• Proposed Staff Response – The staff has revised the sentence to
read “UHS mechanical components, such as pumps, valves, and
cooling tower fans, should automatically start and open/close as
appropriate to support DBA heat loads. If the UHS mechanical
component does not incorporate design features that automatically
start and open/close components, operator actions are required to
support its intended safety function. For example, placing UHS
safety-related makeup water in service to the UHS cooling tower may
require operator actions to start makeup pumps to satisfy the 30 days
UHS water inventory. RG 1.62, “Manual Initiation of Protective
Actions” provides guidance for manual initiation of protective actions.”
14
Addressing Subcommittee Comments
• The guidance provided in RG 1.27 Rev 3 is applicable to plants with
active safety systems and does not apply to plants that utilize a
passive containment cooling system as their UHS. The ACRS asked
about UHS review guidance for passive plants and whether the
guidance for passive plants should be included in RG 1.27.
• Proposed Staff Response - Passive designs have unique attributes
and have not lent themselves to a common review procedure. The
staff has reviewed these designs on a case-by-case basis and does
not see the benefit in developing a regulatory guide at this time.
• Other comments have been evaluated and incorporated into the RG
as appropriate
15
Conclusions
• RG 1.27 has been revised to address current regulations
and lessons learned from operating experience since the
guide was last revised in 1976
• Revised RG 1.27 provides necessary guidance for nuclear
power plant licensees and applicants to use to establish
UHS features of plant systems required by NRC rules and
regulations
• Public comments received and addressed
• RG 1.27 ready for final publication
16
BACKUP SLIDES
17
Public Comments & NRC Response
Public Comment
NRC Response
Background discussion regarding
design considerations for UHS is too
prescriptive, with some elements
that may not have an established or
NRC endorsed mechanism to
evaluate, and new design inputs
that may belong to 'beyond design
basis' considerations, a process still
in regulatory development.
For example, "consider the effects
of climate changes that might occur
over the design life of the facility”,
etc. What would be the criteria &
methodology to quantify? Moreover,
the Fukushima Flooding Task Force
is working with NRC on various
guidance on dam failures, etc. and
language here is duplicative of other
guidance.
The staff partially disagreed with this comment. In Rev 3 of draft
RG 1.27, the staff added discussions on system design
considerations for the UHS, clarified the meteorological conditions
to be considered and considerations for natural phenomena and
site hazards. The staff disagreed that these discussions represent
beyond design basis scenarios.
Regarding the example cited, the intent of this statement was to
ensure that long-term possible environmental changes are
considered in the design of the UHS. Staff has revised the
sentence to read:
“For natural sources, historical experience indicates that river
blockage (e.g., ice dams or flood debris) or diversion may be
possible, as well as potential changes in ocean, river, or lake levels
as a result of severe natural events, or possible changes in
climatological conditions in the site region resulting from human or
natural causes.”
The staff also added the following in Regulatory position C.1.e:
“Current literature on possible changes in the climatological
conditions in the site region should also be reviewed to be
confident that the methods used to predict weather extremes are
reasonable.”
18
Public Comments & NRC Response
Public Comment
NRC Response
The guidance for scoping of SSC's in the
Maintenance Rule is in NUMARC 93-01
Rev. 4a, and endorsed by R.G. 1.160.
Further, in many cases, the water
controlling structures are not in the
jurisdiction of the licensee, but other
entities. Reference to the Maintenance
Rule should be removed, as it is an
arbitrary inclusion as written.
The staff partially agreed with this comment that not all
water control structures affecting a plant site would be within
the jurisdiction of the licensee/applicant. The discussion of
the Maintenance Rule has been revised to clarify that only
those structures within the jurisdiction of the licensee should
be monitored in accordance with the Maintenance Rule and
RG 1.160. However, it would be prudent for the licensee to
ensure other water controlling structures affecting the safety
of the site are being monitored under another program such
as the US Army Corps of Engineers National Dam
Inspection Program.
19
Public Comments & NRC Response
Public Comment
Missing from this is any consideration of
how sea level rise may impact the
reliability of the UHS during the license
period. Pond banks that were initially
safe may be washed away by enhanced
storm surge for example leaving no
cooling water supply. Cooling water that
was initially fresh may become brackish
and damage equipment not designed for
the changed water chemistry leading to
failure of critical cooling systems.
Changed tidal flow patterns may lead to
accumulation of clogging debris where
the original design prevented this. If the
effects of subsidence on ground water
are to be considered, then surely the
effects of sea level rise up to at least 2
meters by 2080 must be considered as
well.
NRC Response
The staff agreed in part with this comment.
The staff agreed that these are important considerations for
the design of the UHS systems. In fact, the potential
change in sea level was included in the discussion section
of proposed Revision 3 to RG 1.27, which states: “For
natural sources, historical experience indicates that river
blockage (e.g., ice dams or flood debris) or diversion may
be possible, as well as changes in ocean or lake levels as a
result of severe natural events”.
The staff has added a new regulatory position under section
C.2.a to further address this comment:
“(5) potential changes in ocean, river, or lake levels as a
result of severe natural events, or possible changes in
climatological conditions in the site region resulting from
human or natural causes, that may reasonably be expected
to occur during the plant lifetime.”
20
Public Comments & NRC Response
Public Comment
Concern:
Revision 2 of the RG 1.27, required transient
analysis to include the worst 24-hours following
the initial critical time period. This analysis period
should remain part of the design basis analysis
because peak heat loads from a realistic or
conservative analysis may occur several hours
after the start of the initial accident.
Suggested Revision:
Following the site specific UHS critical time period
the worst 24-hour period should be maintained as
a requirement for transient analysis for peak
cooling water temperature.
NRC Response
The proposed revision did not relax considerations
for the transient analysis. Instead, the proposed
revision specified that the meteorological conditions
resulting in the maximum intake water temperature
to the plant should be the worst combination of
controlling parameters for the critical time period(s)
unique to the specific design of the UHS.
Depending on the UHS design, the critical time
period (i.e., the time interval after a DBA to when
the intake water to the plant from the UHS reaches
its maximum value) varies.
In practice, the 24-hour, post-accident time period
has, in many cases, been looked upon as a default
time period. Now rather, the proposed revision
clarifies that the responsibility for defining and
justifying the time period(s) critical to the UHS
design lies with the applicant or licensee.
21
Public Comments & NRC Response
Public Comment
Concern:
The existing guidance allows flexible to
defer cooling of the spent fuel pools to gain
transient analysis margin. Requirements
discussing cooling of spent fuel pools
should be clarified. Also, the existing
guidance allows for significant delays in
cooling the non-accident unit to gain
transient analysis margin. Emergency
procedures direct operates to cool the
units to ensure safety margin. Limiting the
cooling capability for the UHS structure is
inappropriate for a shared safety system
(e.g. a cooling pond). Reducing UHS
cooling capacity in this manner restricts
operational flexibility and reduces plant
safety margin.
Suggested Resolution:
The guidance should prescriptively discuss
cooling requirements and the treatment of
the associated heat loads in transient
analysis to ensure that safety margin is
adequately maintained.
NRC Response
The staff partially agreed with the comment.
An additional safety function was added to the Background
information to further clarifies spent fuel pool cooling:
“The UHS performs three principle safety functions:
(1)……. and (3) dissipation of maximum expected decay
heat from the spent fuel pool to ensure the pool
temperature remains within the design bounds for the
structure,” This addition concurs with the SRP 9.1.3, “Spent
Fuel Pool Cooling and Cleanup System.”
No specified time was included for cooling the non accident
unit because neither GDC 5 nor BTP 5-4 specify a
cooldown time. GDC 5 specifies an orderly shutdown and
cooldown of the accident unit and BTP 5-4, “Design
Requirements of the Residual Heat Removal System,”
Section B 1.D, specifies the RHR system must be capable
of bringing the reactor to a cold shutdown condition, with
only offsite or onsite power available, within a reasonable
period of time following shutdown, assuming the most
limiting single failure.
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